OTTR 10-Q Quarterly Report Sept. 30, 2020

OTTER TAIL CORP

10-Ks and 10-Qs

10-Q	Quarter ended Sept. 30, 2025
10-Q	Quarter ended June 30, 2025
10-Q	Quarter ended March 31, 2025
10-K	Fiscal year ended Dec. 31, 2024
10-Q	Quarter ended Sept. 30, 2024
10-Q	Quarter ended June 30, 2024
10-Q	Quarter ended March 31, 2024
10-K	Fiscal year ended Dec. 31, 2023
10-Q	Quarter ended Sept. 30, 2023
10-Q	Quarter ended June 30, 2023
10-Q	Quarter ended March 31, 2023
10-K	Fiscal year ended Dec. 31, 2022
10-Q	Quarter ended Sept. 30, 2022
10-Q	Quarter ended June 30, 2022
10-Q	Quarter ended March 31, 2022
10-K	Fiscal year ended Dec. 31, 2021
10-Q	Quarter ended Sept. 30, 2021
10-Q	Quarter ended June 30, 2021
10-Q	Quarter ended March 31, 2021
10-K	Fiscal year ended Dec. 31, 2020
10-Q	Quarter ended Sept. 30, 2020
10-Q	Quarter ended June 30, 2020
10-Q	Quarter ended March 31, 2020
10-K	Fiscal year ended Dec. 31, 2019
10-Q	Quarter ended Sept. 30, 2019
10-Q	Quarter ended June 30, 2019
10-Q	Quarter ended March 31, 2019
10-K	Fiscal year ended Dec. 31, 2018
10-Q	Quarter ended Sept. 30, 2018
10-Q	Quarter ended June 30, 2018
10-Q	Quarter ended March 31, 2018
10-K	Fiscal year ended Dec. 31, 2017
10-Q	Quarter ended Sept. 30, 2017
10-Q	Quarter ended June 30, 2017
10-Q	Quarter ended March 31, 2017
10-K	Fiscal year ended Dec. 31, 2016
10-Q	Quarter ended Sept. 30, 2016
10-Q	Quarter ended June 30, 2016
10-Q	Quarter ended March 31, 2016
10-K	Fiscal year ended Dec. 31, 2015
10-Q	Quarter ended Sept. 30, 2015
10-Q	Quarter ended June 30, 2015
10-Q	Quarter ended March 31, 2015
10-K	Fiscal year ended Dec. 31, 2014
10-Q	Quarter ended Sept. 30, 2014
10-Q	Quarter ended June 30, 2014
10-Q	Quarter ended March 31, 2014
10-K	Fiscal year ended Dec. 31, 2013
10-Q	Quarter ended Sept. 30, 2013
10-Q	Quarter ended June 30, 2013
10-Q	Quarter ended March 31, 2013
10-K	Fiscal year ended Dec. 31, 2012
10-Q	Quarter ended Sept. 30, 2012
10-Q	Quarter ended June 30, 2012
10-Q	Quarter ended March 31, 2012
10-K	Fiscal year ended Dec. 31, 2011
10-Q	Quarter ended Sept. 30, 2011
10-Q	Quarter ended June 30, 2011
10-Q	Quarter ended March 31, 2011
10-K	Fiscal year ended Dec. 31, 2010
10-Q	Quarter ended Sept. 30, 2010
10-Q	Quarter ended June 30, 2010
10-Q	Quarter ended March 31, 2010
10-K	Fiscal year ended Dec. 31, 2009

PROXIES

DEF 14A	Filed on March 3, 2025
DEF 14A	Filed on Dec. 31, 2024
DEF 14A	Filed on Feb. 28, 2024
DEF 14A	Filed on Dec. 31, 2023
DEF 14A	Filed on March 1, 2023
DEF 14A	Filed on March 2, 2022
DEF 14A	Filed on Dec. 31, 2021
DEF 14A	Filed on March 3, 2021
DEF 14A	Filed on March 9, 2020
DEF 14A	Filed on Feb. 27, 2019
DEF 14A	Filed on Feb. 28, 2018
DEF 14A	Filed on March 1, 2017
DEF 14A	Filed on March 1, 2016
DEF 14A	Filed on March 3, 2015
DEF 14A	Filed on March 3, 2014
DEF 14A	Filed on Feb. 27, 2013
DEF 14A	Filed on March 7, 2012
DEF 14A	Filed on March 2, 2011
DEF 14A	Filed on March 5, 2010

ottr20200930_10q.htm

Table of Contents

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

☒ QUARTERLY REPORT PURSUANT TO SECTIO N 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the quarterly period ended

September 30, 2020

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the transition period from

Commission file number

0-53713

OTTER TAIL CORPORATION

(Exact name of registrant as specified in its charter)

Minnesota	27-0383995
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

215 South Cascade Street, Box 496 , Fergus Falls , Minnesota	56538-0496
(Address of principal executive offices)	(Zip Code)

866 - 410-8780

(Registrant's telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Shares, par value $5.00 per share	OTTR	The Nasdaq Stock Market LLC

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.:

Large accelerated filer ☑	Accelerated filer ☐

Non-accelerated filer ☐	Smaller reporting company ☐	Emerging growth company ☐

If an emerging growth company, indicate by checkmark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act ☐

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act).

Yes ☐ No ☑

Indicate the number of shares outstanding of each of the issuer's classes of Common Stock, as of the latest practicable date:

October 3 1 , 2020 – 41,064,051 Common Shares ($5 par value)

Table of Contents

OTTER TAIL CORPORATION

INDEX

Part I. Financial Information		Page No.

Item 1.	Financial Statements

	Consolidated Balance Sheets – September 30, 2020 and December 31, 2019 (not audited)	2 & 3

	Consolidated Statements of Income – Three and Nine Months Ended September 30, 2020 and 2019 (not audited)	4

	Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 2020 and 2019 (not audited)	5

	Consolidated Statements of Common Shareholders’ Equity – Three and Nine Months Ended September 30, 2020 and 2019 (not audited)	6

	Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2020 and 2019 (not audited)	7

	Condensed Notes to Consolidated Financial Statements (not audited)	8-33

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	34-52

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52

Item 4.	Controls and Procedures	52

Part II. Other Information

Item 1.	Legal Proceedings	53

Item 1A.	Risk Factors	53

Item 6.	Exhibits	54

Signatures		54

Table of Contents

PART I. FINANCIAL INFORMATION

I tem 1. F inancial S tatements

Otter Tail Corporation
Consolidated Balance Sheets
(not audited)

(in thousands)	September 30 , 20 20		December 31, 20 19

Assets

Current Assets
Cash and Cash Equivalents	$	44,904	$	21,199
Accounts Receivable:
Trade—Net		100,423		77,947
Other		6,322		8,773
Inventories		81,871		97,851
Unbilled Receivables		16,409		20,911
Income Taxes Receivable		-		1,487
Regulatory Assets		17,435		21,650
Other		7,552		5,042
Total Current Assets		274,916		254,860

Investments		10,791		9,894
Other Assets		42,316		40,196
Goodwill		37,572		37,572
Other Intangibles — Net		10,419		11,290
Regulatory Assets		145,977		144,138

Right of Use Asset s - Operating Leases		19,713		21,851

Plant
Electric Plant in Service		2,221,785		2,212,884
Nonelectric Operations		256,480		247,356
Construction Work in Progress		454,128		185,238
Total Gross Plant		2,932,393		2,645,478
Less Accumulated Depreciation and Amortization		939,590		891,684
Net Plant		1,992,803		1,753,794

Total Assets	$	2,534,507	$	2,273,595

See accompanying condensed notes to consolidated financial statements.

Table of Contents

Otter Tail Corporation
Consolidated Balance Sheets
(not audited)

(in thousands, except share data)	September 30 , 20 20			December 31, 20 1 9

Liabilities and Equity

Current Liabilities
Short-Term Debt	$	48,600		$	6,000
Current Maturities of Long-Term Debt		215			183
Accounts Payable		189,327			120,775
Accrued Salaries and Wages		20,933			22,730
Accrued Taxes		14,283			17,525
Regulatory Liabilities		12,870			7,480
Current Operating Lease Liabilities		4,581			4,136
Other Accrued Liabilities		8,927			10,912
Total Current Liabilities		299,736			189,741

Pensions Benefit Liability		86,101			98,970
Other Postretirement Benefits Liability		72,508			71,437
Long-Term Operating Lease Liabilities		15,778			18,193
Other Noncurrent Liabilities		35,146			30,833

Commitments and Contingencies (note 9 )

Deferred Credits
Deferred Income Taxes		152,448			131,941
Deferred Tax Credits		17,640			18,626
Regulatory Liabilities		236,892			239,906
Other		1,914			2,885
Total Deferred Credits		408,894			393,358

Capitalization
Long-Term Debt—Net		764,274			689,581

Cumulative Preferred Shares – Authorized 1,500,000 Shares Without Par Value; Outstanding – None		-			-

Cumulative Preference Shares – Authorized 1,000,000 Shares Without Par Value; Outstanding – None		-			-

Common Shares, Par Value $5 Per Share—Authorized, 50,000,000 Shares; Outstanding, 2020— 41,052,165 Shares; 2019— 40,157,591 Shares		205,261			200,788
Premium on Common Shares		398,301			364,790
Retained Earnings		254,468			222,341
Accumulated Other Comprehensive Loss		( 5,960	)		( 6,437	)
Total Common Equity		852,070			781,482
Total Capitalization		1,616,344			1,471,063
Total Liabilities and Equity	$	2,534,507		$	2,273,595

See accompanying condensed notes to consolidated financial statements.

Table of Contents

Otter Tail Corporation
Consolidated Statements of Income
(not audited)

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands, except share and per-share amounts)	2020		2019			2020		2019
Operating Revenues
Electric:
Revenues from Contracts with Customers	$	112,435	$	115,285		$	330,313	$	346,291
Changes in Accrued Revenues under Alternative Revenue Programs		2,778		( 921	)		2,900		( 1,601	)
Total Electric Revenues		115,213		114,364			333,213		344,690
Product Sales from Contracts with Customers		120,542		114,288			330,045		359,137
Total Operating Revenues		235,755		228,652			663,258		703,827
Operating Expenses
Production Fuel – Electric		11,554		18,331			34,077		45,547
Purchased Power – Electric System Use		13,428		13,163			45,940		54,748
Electric Operation and Maintenance Expenses		32,845		35,869			106,639		114,107
Cost of Products Sold (depreciation included below)		86,856		88,747			246,567		277,325
Other Nonelectric Expenses		13,615		11,665			36,277		38,404
Depreciation and Amortization		20,395		19,657			61,230		58,229
Property Taxes – Electric		4,333		3,965			12,601		11,824
Total Operating Expenses		183,026		191,397			543,331		600,184
Operating Income		52,729		37,255			119,927		103,643
Interest Charges		8,568		7,539			25,353		23,190
Nonservice Cost Components of Postretirement Benefits		842		1,055			2,581		3,165
Other Income		1,712		1,020			3,733		3,114
Income Before Income Taxes		45,031		29,681			95,726		80,402
Income Tax Expense		9,097		4,936			18,543		13,907
Net Income		35,934	$	24,745			77,183	$	66,495

Average Number of Common Shares Outstanding – Basic		40,913,972		39,714,672			40,548,133		39,694,677
Average Number of Common Shares Outstanding – Diluted		41,077,689		39,946,739			40,732,928		39,922,580

Basic Earnings Per Common Share	$	0.88	$	0.62		$	1.90	$	1.68

Diluted Earnings Per Common Share	$	0.87	$	0.62		$	1.89	$	1.67

See accompanying condensed notes to consolidated financial statements.

Table of Contents

Otter Tail Corporation
Consolidated Statements of Comprehensive Income
(not audited)

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	20 20			201 9			20 20			201 9
Net Income	$	35,934		$	24,745		$	77,183		$	66,495
Other Comprehensive Income:
Unrealized Gains on Available-for-Sale Securities:
Reversal of Previously Recognized (Gains) Losses Realized on Sale of Investments and Included in Other Income During Period		( 21	)		( 1	)		13			( 5	)
Unrealized (Losses) Gains Arising During Period		( 13	)		30			205			187
Income Tax Savings (Expense)		7			( 6	)		( 46	)		( 38	)
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax		( 27	)		23			172			144
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Lossesand Costs (note 11)		138			130			413			389
Income Tax Expense		( 36	)		( 34	)		( 108	)		( 101	)
Pension and Postretirement Benefit Plans – net-of-tax		102			96			305			288
Total Other Comprehensive Income		75			119			477			432
Total Comprehensive Income	$	36,009		$	24,864		$	77,660		$	66,927

See accompanying condensed notes to consolidated financial statements.

Table of Contents

Otter Tail Corporation

Consolidated Statements of Common Shareholders’ Equity

For the Three- and Nine -Month Periods Ended September 30, 2020 and 2019

(not audited)

(in thousands, except common shares outstanding)	Common Shares Outstanding			Par Value, Common Shares			Premium on Common Shares			Retained Earnings			Accumulated Other Comprehensive Income/(Loss)			Total Common Equity
Balance, June 30, 2020		40,848,828		$	204,244		$	390,141		$	233,705		$	( 6,035	)	$	822,055
Common Stock Issuances, Net of Expenses		203,337			1,017			6,885									7,902
Net Income											35,934						35,934
Other Comprehensive Income														75			75
Employee Stock Incentive Plan Expense								1,275									1,275
Common Dividends ( $0.37 per share)											( 15,171	)					( 15,171	)
Balance, September 30, 2020		41,052,165		$	205,261		$	398,301		$	254,468		$	( 5,960	)	$	852,070

Balance, June 30, 2019		39,754,902		$	198,775		$	345,030		$	205,115		$	( 4,615	)	$	744,305
Common Stock Issuances, Net of Expenses		375			1			( 37	)								( 36	)
Net Income											24,745						24,745
Other Comprehensive Income														119			119
Employee Stock Incentive Plan Expense								1,301									1,301
Common Dividends ( $0.35 per share)											( 13,929	)					( 13,929	)
Balance, September 30, 2019		39,755,277		$	198,776		$	346,294		$	215,931		$	( 4,496	)	$	756,505

Balance, December 31, 2019		40,157,591		$	200,788		$	364,790		$	222,341		$	( 6,437	)	$	781,482
Common Stock Issuances, Net of Expenses		932,791			4,664			30,107									34,771
Common Stock Retirements		( 38,217	)		( 191	)		( 1,878	)								( 2,069	)
Net Income											77,183						77,183
Other Comprehensive Income														477			477
Employee Stock Incentive Plan Expense								5,282									5,282
Common Dividends ( $1.11 per share)											( 45,056	)					( 45,056	)
Balance, September 30, 2020		41,052,165		$	205,261		$	398,301		$	254,468		$	( 5,960	)	$	852,070

Balance, December 31, 2018		39,664,884		$	198,324		$	344,250		$	190,433		$	( 4,144	)	$	728,863
Common Stock Issuances, Net of Expenses		145,617			728			( 747	)								( 19	)
Common Stock Retirements		( 55,224	)		( 276	)		( 2,454	)								( 2,730	)
Net Income											66,495						66,495
Other Comprehensive Income														432			432
ASU 2018-02 2017 TCJA Stranded Tax Transfer											784			( 784	)		-
Employee Stock Incentive Plan Expense								5,245									5,245
Common Dividends ( $1.05 per share)											( 41,781	)					( 41,781	)
Balance, September 30, 2019		39,755,277		$	198,776		$	346,294		$	215,931		$	( 4,496	)	$	756,505

Table of Contents

Otter Tail Corporation
Consolidated Statements of Cash Flows
(not audited)

	Nine Months Ended September 30 ,
(in thousands)	20 20			20 19
Operating Activities
Net Income	$	77,183		$	66,495
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation and Amortization		61,230			58,229
Deferred Tax Credits		( 986	)		( 1,011	)
Deferred Income Taxes		20,353			3,487
Change in Deferred Debits and Other Assets		3,439			7,142
Discretionary Contribution to Pension Plan		( 11,200	)		( 22,500	)
Change in Noncurrent Liabilities and Deferred Credits		3,237			10,344
Allowance for Equity/Other Funds Used During Construction		( 3,104	)		( 1,602	)
Stock Compensation Expense		5,282			5,245
Other—Net		( 176	)		312
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables		( 20,025	)		( 16,213	)
Change in Inventories		15,980			9,218
Change in Other Current Assets		2,023			2,974
Change in Payables and Other Current Liabilities		( 12,063	)		( 20,744	)
Change in Interest and Income Taxes Receivable/Payable		103			3,773
Net Cash Provided by Operating Activities		141,276			105,149
Investing Activities
Capital Expenditures		( 220,630	)		( 149,695	)
Proceeds from Disposal of Noncurrent Assets		4,617			4,111
Cash Used for Investments and Other Assets		( 6,372	)		( 5,546	)
Net Cash Used in Investing Activities		( 222,385	)		( 151,130	)
Financing Activities
Change in Checks Written in Excess of Cash		90			383
Net Short-Term Borrowings		42,600			90,398
Proceeds from Issuance of Common Stock		35,219			-
Common Stock Issuance Expenses		( 465	)		( 35	)
Payments for Shares Withheld for Employee Tax Obligations		( 2,069	)		( 2,730	)
Proceeds from Issuance of Long-Term Debt		75,000			-
Short-Term and Long-Term Debt Issuance Expenses		( 369	)		( 66	)
Payments for Retirement of Long-Term Debt		( 136	)		( 128	)
Dividends Paid		( 45,056	)		( 41,781	)
Net Cash Provided by Financing Activities		104,814			46,041
Net Change in Cash and Cash Equivalents		23,705			60
Cash and Cash Equivalents at Beginning of Period		21,199			861
Cash and Cash Equivalents at End of Period	$	44,904		$	921

See accompanying condensed notes to consolidated financial statements.

Table of Contents

O TTER TAIL CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(not audited)

In the opinion of management, Otter Tail Corporation (the Company) has included all adjustments (including normal recurring accruals) necessary for a fair presentation of the consolidated financial statements for the periods presented. The consolidated financial statements and condensed notes thereto should be read in conjunction with the consolidated financial statements and notes included in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2019. Because of the coronavirus (COVID-19) pandemic, the seasonality of our businesses and other factors, the earnings for the three and nine months ended September 30, 2020 should not be taken as an indication of earnings for all or any part of the balance of the year.

1. Summary of Significant Accounting Policies

Revenue Recognition

Due to the diverse business operations of the Company, recognition of revenue from contracts with customers depends on the product produced and sold or service performed. The Company recognizes revenue from contracts with customers at prices that are fixed or determinable as evidenced by an agreement with the customer, when the Company has met its performance obligation under the contract and it is probable that the Company will collect the amount to which it is entitled in exchange for the goods or services transferred or to be transferred to the customer. Depending on the product produced and sold or service performed and the terms of the agreement with the customer, the Company recognizes revenue either over time, in the case of delivery or transmission of electricity or related services or the production and storage of certain custom-made products, or at a point in time for the delivery of standardized products and other products made to the customer’s specifications where the terms of the contract require transfer of the completed product. Provisions for sales returns, early payment terms discounts, volume-based variable pricing incentives and warranty costs are recorded as reductions to revenue at the time revenue is recognized based on customer history, historical information and current trends.

In addition to recognizing revenue from contracts with customers under Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 606, Revenue from Contracts with Customers (ASC 606 ), the Company also records adjustments to Electric segment revenues for amounts subject to future collection under alternative revenue programs (ARPs) as defined in ASC Topic 980, Regulated Operations (ASC 980 ). The ARP revenue adjustments are recorded on the basis of recoverable costs incurred and returns earned under rate riders on a separate line on the face of the Company’s consolidated statements of income as they do not meet the criteria to be classified as revenue from contracts with customers.

Electric Segment Revenues —In the Electric segment, the Company recognizes revenue in two categories: ( 1 ) revenues from contracts with customers and ( 2 ) adjustments to revenues for amounts collectible under ARPs.

Most Electric segment revenues are earned from the generation, transmission and sale of electricity to retail customers at rates approved by regulatory commissions in the states where Otter Tail Power Company (OTP) provides service. OTP also earns revenue from the transmission of electricity for others over the transmission assets it owns separately, or jointly with other transmission service providers, under rate tariffs established by the independent transmission system operator and approved by the Federal Energy Regulatory Commission (FERC). A third source of revenue for OTP comes from the generation and sale of electricity to wholesale customers at contract or market rates. Revenues from all these sources meet the criteria to be classified as revenue from contracts with customers and are recognized over time as energy is delivered or transmitted. Revenue is recognized based on the metered quantity of electricity delivered or transmitted at the applicable rates. For electricity delivered and consumed after a meter is read but prior to the end of the reporting period, OTP records revenue and an unbilled receivable based on estimates of the kilowatt-hours (kwh) of energy delivered to the customer.

ARPs provide for adjustments to rates outside of a general rate case proceeding, usually as a surcharge applied to future billings typically through the use of rate riders subject to periodic adjustments, to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. ARP riders generally provide for the recovery of specified costs and investments and include an incentive component to provide the regulated utility with a return on amounts invested.

OTP has recovered costs and earned incentives or returns on investments subject to recovery under several ARP rate riders, including:

●

In Minnesota: Transmission Cost Recovery (TCR), Environmental Cost Recovery (ECR), Renewable Resource Adjustment (RRA), Energy Intensive Trade Exposed and Conservation Improvement Program (CIP) riders.

●

In North Dakota: TCR, ECR, Renewable Resource Cost Recovery and Generation Cost Recovery (GCR) riders.

●

In South Dakota: TCR, ECR, Phase-In Rate Plan and Energy Efficiency Plan (conservation) riders.

Table of Contents

OTP accrues ARP revenue based on costs incurred, investments made and returns on those investments that qualify for recovery through established riders. Amounts billed under riders in effect at the time of the billing are included in revenues from contracts with customers net of amounts billed that are subject to refund through future rider adjustments. Amounts accrued and subject to recovery through future rider rate updates and adjustments are reported as changes in accrued revenues under ARPs on a separate line in the revenue section of the Company’s consolidated statement of income. See table in note 3 for total revenues billed and accrued under ARP riders for the three - and nine -month periods ended September 30, 2020 and 2019.

Manufacturing Segment Revenues —Companies in the Manufacturing segment, BTD Manufacturing, Inc. (BTD) and T.O. Plastics, Inc. (T.O. Plastics), earn revenue predominantly from the production and delivery of custom-made or standardized parts to customers across several industries. BTD also earns revenue from the production and sale of tools and dies to other manufacturers. For the production and delivery of standardized products and other products made to customer specifications where the terms of the contract require transfer of the completed product, the operating company has met its performance obligation and recognizes revenue at the point in time when the product is shipped. For revenue recognized on products when shipped, the operating companies have no further obligation to provide services related to such products. The shipping terms used in these instances are FOB shipping point.

Plastics Segment Revenues —Companies in our Plastics segment earn revenue predominantly from the sale and delivery of standardized polyvinyl chloride (PVC) pipe products produced at their manufacturing facilities. Revenue from the sale of these products is recognized at the point in time when the product is shipped based on prices agreed to in a purchase order. For revenue recognized on shipped products, there is no further obligation to provide services related to such products. The shipping terms used in these instances are FOB shipping point. The Plastics segment has one customer for which it produces and stores a product made to the customer’s specifications and design under a build and hold agreement. For sales to this customer, the operating company recognizes revenue as the custom-made product is produced, adjusting the amount of revenue for volume rebate variable pricing considerations the operating company expects the customer will earn and applicable early payment discounts the company expects the customer will take. Ownership of the pipe transfers to the customer prior to delivery and the operating company is paid a negotiated fee for storage of the pipe.

See operating revenue table in note 2 for a disaggregation of the Company’s revenues by business segment for the three - and nine -month periods ended September 30, 2020 and 2019.

Agreements Subject to Legally Enforceable Netting Arrangements

OTP has certain derivative contracts that are designated as normal purchases. Individual counterparty exposures for these contracts can be offset according to legally enforceable netting arrangements. The Company does not offset assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet.

Fair Value Measurements

The Company follows ASC Topic 820, Fair Value Measurements and Disclosures (ASC 820 ), for recurring fair value measurements. ASC 820 provides a single definition of fair value, requires enhanced disclosures about assets and liabilities measured at fair value and establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the hierarchy and examples of each level are as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange.

Level 2 – Pricing inputs are other than quoted prices in active markets but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.

Level 3 – Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation and may include complex and subjective models and forecasts.

Table of Contents

The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2020 and December 31, 2019:

September 30 , 20 20 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds – Held by Captive Insurance Company	$	1,665
Corporate Debt Securities – Held by Captive Insurance Company			$	2,887
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				6,131
Other Assets:
Money Market and Mutual Funds –Retirement Plans		1,582
Total Assets	$	3,247	$	9,018

December 31, 20 19 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds – Held by Captive Insurance Company	$	1,586
Corporate Debt Securities – Held by Captive Insurance Company			$	2,124
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				6,060
Other Assets:
Money Market and Mutual Funds –Retirement Plans		2,363
Total Assets	$	3,949	$	8,184

The level 2 fair values for Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company are determined on the basis of valuations provided by a third -party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes.

Coyote Station Lignite Supply Agreement – Variable Interest Entity

In October 2012 the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of lignite coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton paid by the Coyote Station owners under the LSA reflects the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are required to buy certain assets of CCMC at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC because the Coyote Station owners are required to buy the membership interests of CCMC at the end of the contract term at equity value. No single owner of Coyote Station owns a majority interest in Coyote Station or has the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered a primary beneficiary of the VIE and the Company is not required to include CCMC in its consolidated financial statements.

If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and the Coyote Station owners purchase all of the outstanding membership interests of CCMC, the owners will satisfy (or if permitted by CCMC’s applicable lender assume) all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. In the event the contract is terminated prior to the end of the term due to certain events, OTP’s maximum exposure to additional costs, as a result of its involvement with CCMC, and potential impairment loss if recovery of those costs is denied by regulatory authorities, could be as high as approximately $ 50 million, OTP’s 35 % share of CCMC’s unrecovered costs as of September 30, 2020.

Table of Contents

Inventories

Inventories, valued at the lower of cost or net realizable value, consist of the following:

	September 30,		December 31,
(in thousands)	2020		2019
Finished Goods	$	18,901	$	31,863
Work in Process		14,480		16,508
Raw Material, Fuel and Supplies		48,490		49,480
Total Inventories	$	81,871	$	97,851

Intangible Assets

Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360 - 10 - 35, Property, Plant, and Equipment—Overall—Subsequent Measurement .

The following table summarizes the components of the Company’s intangible assets at September 30, 2020 and December 31, 2019:

September 30 , 20 20 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	12,095	$	10,396	79 - 179
Other		26		3		23	216
Total	$	22,517	$	12,098	$	10,419

December 31, 20 19 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	11,259	$	11,232	88 - 188
Other		179		121		58	8 - 45
Total	$	22,670	$	11,380	$	11,290

The amortization expense for these intangible assets was:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2020		2019		2020		2019
Amortization Expense – Intangible Assets	$	284	$	296	$	871	$	888

The estimated annual amortization expense for these intangible assets for the next 51 months is:

(in thousands)		2020				2021				2022				2023				2024
Estimated Amortization Expense – Intangible Assets		$	275			$	1,100			$	1,100			$	1,100			$	1,100

Supplemental Disclosures of Cash Flow Information

	As of September 30,
(in thousands)	2020		2019
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$	112,314	$	15,893

Table of Contents

New Accounting Standards Adopted

ASU 2016 - 13 —In June 2016 the FASB issued Accounting Standards Update (ASU) No. 2016 - 13, Financial Instruments—Credit Losses (Topic 326 ) (ASC 326 ) , which changes how entities account for credit losses on receivables and certain other assets effective for interim and annual periods beginning on or after December 31, 2019. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards. The Company adopted ASC 326 in the first quarter of 2020. Adoption of the new standard did not have a material impact on the Company’s consolidated financial statements, and the Company did not record a cumulative effect adjustment to retained earnings on adoption.

Accounting Policy

Trade account and unbilled receivables reflected in the Company’s consolidated balance sheets represent the net amounts expected to be collected. An allowance for credit losses is established based on expected losses. Expected losses are estimated by reviewing individual accounts, considering aging, financial condition of the debtor for certain accounts, recent payment history, current and forecasted economic conditions and other relevant factors.

Allowance for Credit Losses

Following is a summary of activity in allowances for credit losses on trade and unbilled accounts receivable across the Company:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2020			2019			2020			2019
Beginning Balance	$	2,100		$	1,691		$	1,339		$	1,407
Additions Charged to Expense (net of recoveries)		474			86			1,845			549
Reductions for Amounts Written Off		( 313	)		( 225	)		( 923	)		( 404	)
Ending Balance	$	2,261		$	1,552		$	2,261		$	1,552

ASU 2018 - 15 —In August 2018 the FASB issued ASU No. 2018 - 15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350 - 40 ), which amends ASC 350 - 40, Internal-Use Software , to address a customer's accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. The amendments in ASU 2018 - 15 align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal-use software license). Accordingly, the amendments in ASU 2018 - 15 require an entity (customer) in a hosting arrangement that is a service contract to follow the guidance in ASC 350 - 40 to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The amendments in ASU 2018 - 15 also require the entity to present the expense related to the capitalized implementation costs in the same line item in the statement of income as the fees associated with the hosting element (service) of the arrangement and classify payments for capitalized implementation costs in the statement of cash flows in the same manner as payments made for fees associated with the hosting element. The entity is also required to present the capitalized implementation costs in the statement of financial position in the same line item that a prepayment for the fees of the associated hosting arrangement would be presented. The amendments in ASU 2018 - 15 were effective for interim and annual periods beginning on or after December 15, 2019 with early adoption permitted in any interim period. The Company adopted the amendments in ASU 2018 - 15 in the first quarter of 2020. There was no impact to its consolidated financial statements on adoption, but the Company will begin capitalizing implementation costs incurred in cloud computing arrangements post-adoption.

Table of Contents

2. Segment Information

The accounting policies of the segments are described under note 1 – Summary of Significant Accounting Policies. The Company's businesses have been classified into three segments to be consistent with its business strategy and the reporting and review process used by the Company’s chief operating decision maker. These businesses sell products and provide services to customers primarily in the United States. The Company’s business structure currently includes the following three segments: Electric, Manufacturing and Plastics. The chart below indicates the companies included in each segment.

Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota by OTP. In addition, OTP is a participant in the Midcontinent Independent System Operator, Inc. (MISO) markets. OTP’s operations have been the Company’s primary business since 1907.

Manufacturing consists of businesses in the following manufacturing activities: contract machining, metal parts stamping, fabrication and painting, and production of plastic thermoformed horticultural containers, life science and industrial packaging, and material handling components. These businesses have manufacturing facilities in Georgia, Illinois and Minnesota and sell products primarily in the United States.

Plastics consists of businesses producing PVC pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the United States, west of the Mississippi River.

OTP is a wholly owned subsidiary of the Company. All of the Company’s other businesses are owned by its wholly owned subsidiary, Varistar Corporation. The Company’s Corporate operating costs include items such as corporate staff and overhead costs, the results of the Company’s captive insurance company and other items excluded from the measurement of operating segment performance. Corporate assets consist primarily of cash, prepaid expenses, investments and fixed assets. Corporate is not an operating segment. Rather, it is added to operating segment totals to reconcile to totals on the Company’s consolidated financial statements.

While no single customer accounted for over 10% of consolidated revenue in 2019, certain customers provided a significant portion of each business segment’s 2019 revenue. The Electric segment has one customer that provided 11.9 % of 2019 segment revenues. The Manufacturing segment has one customer that manufactures and sells recreational vehicles that provided 23.8 % of 2019 segment revenues and one customer that manufactures and sells lawn and garden equipment that provided 11.1 % of 2019 segment revenues. The Manufacturing segment’s top five revenue-generating customers provided over 54 % of 2019 segment revenues. The Plastics segment has two customers that individually provided 25.3 % and 20.4 % of 2019 segment revenues. The loss of any one of these customers would have a significant negative impact on the financial position and results of operations of the respective business segment and the Company.

All of the Company’s long-lived assets are within the United States and sales within the United States accounted for 98.9 % and 98.5 % of operating revenues for the respective three -month periods ended September 30, 2020 and 2019, and 99.0 % and 98.7 % of operating revenues for the respective nine -month periods ended September 30, 2020 and 2019.

Table of Contents

The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for the three - and nine -month periods ended September 30, 2019 and 2020 and total assets by business segment as of September 30, 2020 and December 31, 2019 are presented in the following tables:

Operating Revenue

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2020			2019			2020			2019
Electric Segment:
Retail Sales Revenue from Contracts with Customers	$	96,827		$	100,345		$	288,861		$	303,276
Changes in Accrued ARP Revenues		2,778			( 921	)		2,900			( 1,601	)
Total Retail Sales Revenue		99,605			99,424			291,761			301,675
Transmission Services Revenue		12,288			11,692			32,802			34,023
Wholesale Revenues – Company Generation		1,500			1,631			3,141			4,099
Other Revenues		1,830			1,626			5,548			4,929
Total Electric Segment Revenues		115,223			114,373			333,252			344,726
Manufacturing Segment:
Metal Parts and Tooling		50,957			56,255			145,435			185,520
Plastic Products and Tooling		7,600			8,088			25,323			26,486
Other		1,292			1,379			3,518			5,034
Total Manufacturing Segment Revenues		59,849			65,722			174,276			217,040
Plastics Segment – Sale of PVC Pipe Products		60,693			48,566			155,769			142,100
Intersegment Eliminations		( 10	)		( 9	)		( 39	)		( 39	)
Total	$	235,755		$	228,652		$	663,258		$	703,827

Interest Charges

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2020		2019		2020		2019
Electric	$	7,334	$	6,300	$	22,066	$	19,566
Manufacturing		553		561		1,661		1,791
Plastics		163		197		497		561
Corporate and Intersegment Eliminations		518		481		1,129		1,272
Total	$	8,568	$	7,539	$	25,353	$	23,190

Income Taxes

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2020			2019			2020			2019
Electric	$	6,048		$	4,066		$	12,247		$	9,874
Manufacturing		891			285			2,163			2,888
Plastics		3,638			1,914			7,373			5,287
Corporate		( 1,480	)		( 1,329	)		( 3,240	)		( 4,142	)
Total	$	9,097		$	4,936		$	18,543		$	13,907

Net Income (Loss)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2020			2019			2020			2019
Electric	$	24,737		$	17,682		$	54,225		$	43,884
Manufacturing		3,311			3,155			8,476			11,987
Plastics		10,343			5,397			20,922			14,918
Corporate		( 2,457	)		( 1,489	)		( 6,440	)		( 4,294	)
Total	$	35,934		$	24,745		$	77,183		$	66,495

Table of Contents

Identifiable Assets

	September 30,		December 31,
(in thousands)	2020		2019
Electric	$	2,191,215	$	1,931,525
Manufacturing		189,525		195,742
Plastics		104,661		92,049
Corporate		49,106		54,279
Total	$	2,534,507	$	2,273,595

3. Rate and Regulatory Matters

Below are descriptions of OTP’s major capital expenditure projects that are expected to have a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of specific electric rate or rider proceedings with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the FERC, impacting OTP’s revenues in 2020 and 2019.

Major Capital Expenditure Projects

Merricourt Wind Energy Center (Merricourt) —On November 16, 2016 OTP entered into an Asset Purchase Agreement (the Purchase Agreement) with EDF Renewable Development, Inc. and certain of its affiliated companies (collectively, EDF) to purchase the development assets and assume certain specified liabilities associated with Merricourt, a 150 -megawatt (MW) wind farm in southeastern North Dakota, for a purchase price of approximately $ 34.7 million, subject to adjustments for interconnection costs. Also on November 16, 2016, OTP entered into a Turnkey Engineering, Procurement and Construction Services Agreement (the TEPC Agreement) with EDF-RE US Development, LLC (EDF-USD) pursuant to which EDF-USD will develop, design, procure, construct, interconnect, test and commission the wind farm with a targeted completion date in 2020 for consideration of approximately $ 200.5 million, subject to certain adjustments, payable following the closing of the Purchase Agreement in installments in connection with certain project construction milestones. In connection with action by the FERC, OTP and EDF-US agreed, in the First Amendment to the Purchase Agreement and the TEPC Agreement dated June 11, 2019, to change the purchase price to $ 37.7 million and to make a related reallocation of responsibility for interconnection costs and liabilities. On July 16, 2019 OTP closed on the purchase of substantially all of the development assets and assumed certain specified liabilities from EDF related to Merricourt pursuant to the Purchase Agreement, as amended, for a purchase price of approximately $ 37.7 million, subject to certain adjustments, and issued the notice to EDF-USD to begin construction in August 2019. The agreements contain customary representations, warranties, covenants and indemnities for this type of transaction. The Merricourt generator interconnection agreement with MISO was approved by the FERC in April 2019.

OTP is earning a return in all three states served by OTP on amounts invested in Merricourt while the project is under construction. Returns are recovered in Minnesota and North Dakota through RRA riders and in South Dakota through the Phase-In Rate Plan Rider. As of September 30, 2020, OTP had capitalized approximately $ 231.1 million in project costs and allowance for funds used during construction (AFUDC) associated with Merricourt. While work on the project continues and commissioning of the wind turbines is in process, OTP has received Notices of Force Majeure from EDF-USD claiming rights to an extension of guaranteed project completion dates and adjustments to the consideration agreed upon in the TEPC Agreement due to COVID- 19 impacts. While details regarding these claims and the related impacts to the project remain uncertain, OTP currently anticipates Merricourt will be in commercial operation by the end of December 2020.

Astoria Station —OTP is constructing this 245 MW simple-cycle natural gas-fired combustion turbine generation facility near Astoria, South Dakota as part of its plan to reliably meet customers’ electric needs, replace expiring capacity purchase agreements and prepare for the planned retirement of its Hoot Lake Plant in 2021. A final order granting an Advanced Determination of Prudence for Astoria Station was issued by the NDPSC on November 3, 2017, subject to certain qualifications and compliance obligations. On August 3, 2018 the SDPUC issued an order granting a site permit for Astoria Station. In a September 26, 2018 hearing the NDPSC established a GCR Rider for future recovery of costs incurred for Astoria Station. On March 6, 2019 the SDPUC issued an order approving a settlement that allows a phase-in rider which includes recovery of Astoria Station costs. The interconnection agreement for Astoria Station was executed by MISO in December 2018 and accepted by the FERC in January 2019. Site preparation and excavation began in May 2019, and construction is occurring on the site. As of September 30, 2020, OTP had capitalized approximately $ 131.6 million in project costs and AFUDC associated with Astoria Station. OTP currently expects this project to begin commercial operation in the first quarter of 2021.

Table of Contents

General Rates

Minnesota —The MPUC rendered its final decision in OTP’s 2016 general rate case in March 2017 and issued its written order on May 1, 2017. Pursuant to the order, OTP’s allowed rate of return on rate base is 7.5056 % and its allowed rate of return on equity (ROE) is 9.41 %.

The MPUC’s order also included: ( 1 ) the determination that all costs (including FERC allocated costs and revenues) of the Big Stone South–Brookings and Big Stone South–Ellendale Multi-Value Projects (MVPs) will be included in the Minnesota TCR Rider and jurisdictionally allocated to OTP’s Minnesota customers (see discussion under Minnesota Transmission Cost Recovery Rider below), and ( 2 ) approval of OTP’s proposal to transition rate base, expenses and revenues from ECR and TCR Riders to base rate recovery, which occurred when final rates were implemented on November 1, 2017. Certain MISO expenses and revenues remain in the TCR Rider to allow for the ongoing refund or recovery of these variable revenues and costs.

On November 2, 2020 OTP filed a request with the MPUC for an increase in revenue recoverable under general rates in Minnesota. In its filing, OTP requested a net increase in annual revenue of approximately $ 14.5 million, or 6.77 %, based on an allowed rate of return on rate base of 7.59 % and an allowed rate of return on equity of 10.20 % on an equity ratio of 52.5 % of total capital. Through this rate case proceeding, OTP is proposing to recover, at the start of interim rates, revenue currently subject to recovery under Minnesota RRA and TCR riders. OTP is also proposing to move the cost of energy from base rates to full recovery under the Energy Adjustment Rider per a prior MPUC order. OTP is also proposing to move recovery of all CIP expenditures out of base rates to the CIP Rider with the implementation of final rates. An interim rate increase is expected to go into effect in January 2021.

North Dakota —On March 23, 2018 OTP made a supplemental filing to its initial request for a rate review, reducing its request for an annual revenue increase from $ 13.1 million to $ 7.1 million, a 4.8 % annual increase. The $ 6.0 million decrease included $ 4.8 million related to tax reform and $ 1.2 million related to other updates.

In a September 26, 2018 hearing the NDPSC approved an overall annual revenue increase of $ 4.6 million ( 3.1 %) and a ROE of 9.77 % on a 52.5 % equity capital structure. The NDPSC’s approval established a GCR Rider for future recovery of costs incurred for Astoria Station. The net revenue increase reflected a reduction in income tax recovery requirements related to the 2017 Tax Cuts and Jobs Act (TCJA) and decreases in rider revenue recovery requirements. Final rates were effective February 1, 2019, with refunds of excess revenues collected under interim rates applied to customers’ April 2019 bills, including $ 0.8 million for amounts collected reflecting the higher tax rates under interim rates in effect in January and February 2018.

South Dakota —On April 20, 2018 OTP filed a request with the SDPUC to increase non-fuel rates in South Dakota by approximately $ 3.3 million annually, or 10.1 %, as the first step in a two -step request. Interim rates were effective October 18, 2018. The second step in the request was an additional 1.7 % revenue increase to recover costs for Merricourt when the wind generation facility goes into service. The SDPUC approved a partial settlement on March 1, 2019 on all issues of the rate case except ROE. The partial settlement included approval of a phase-in plan to provide for a return on amounts invested in Astoria Station and Merricourt, which addressed the second step of the request for increased rates in South Dakota. The partial settlement also included a moratorium on filing another general rate case in South Dakota until the new generation projects have been in service for a year. The partial settlement also allowed OTP to retain the impact of lower tax rates related to the TCJA from January 1, 2018 through October 17, 2018 resulting in the reversal of an accrued refund liability and recognition of $ 1.0 million in revenue in the first quarter of 2019. The SDPUC approved the ROE portion of the rate case on May 14, 2019 and pursuant to the SDPUC’s May 30, 2019 order, OTP’s allowed ROE was set at 8.75 %, resulting in an annual revenue increase of approximately $ 2.2 million. Final rates went into effect August 1, 2019. An interim rate refund for the lower ROE going back to October 18, 2018 was applied to South Dakota customers’ October 2019 bills.

On July 9, 2019 the SDPUC approved a stipulation agreement entered into by OTP with SDPUC staff. The revenue requirement stated in the SDPUC’s final order dated May 30, 2019 understated the amount of OTP's South Dakota share of electric transmission plant in service, resulting in an annual revenue requirement shortfall of approximately $ 341,000 . To address the shortfall, the parties agreed that OTP would file an update to its South Dakota TCR Rider. OTP was authorized full recovery of the transmission rate base correction reflected in the TCR Rider tracker beginning as of the first date of interim rates, October 18, 2018, with the TCR Rider rate update going into effect on October 1, 2019.

To ensure rates are appropriately set under the stipulation, the parties agreed to establish an earnings sharing mechanism to share with customers any weather-normalized earnings above the authorized ROE of 8.75 %. OTP's annual weather-normalized earnings are reported each year by June 1 in its jurisdictional annual report, which will be used to determine the earnings level for purposes of calculating any refund. The earnings sharing mechanism requires that OTP will refund to customers 50 % of

Table of Contents

any weather-normalized revenue that corresponds to the earnings in excess of its authorized ROE, up to a maximum of 9.50 % ROE for a particular year. OTP will refund 100 % of any earnings above 9.50% each year. In the event a refund is due under this provision, OTP will notify the SDPUC of the refund amount and plan for crediting customers within 30 days of filing its South Dakota jurisdictional annual report.

Rate Riders

In addition to general rates, OTP has several rate riders in place in each of its state jurisdictional service areas. These rate riders are designed to recover expenses, costs and returns on rate base investments not currently being recovered in base, or general, rates. In addition to fuel cost recovery riders in each state, OTP has recovered costs and earned incentives or returns on investments subject to recovery under several rate riders, including:

●

In Minnesota: Transmission Cost Recovery (TCR), Environmental Cost Recovery (ECR), Renewable Resource Adjustment (RRA), Energy Intensive Trade Exposed and Conservation Improvement Program riders.

●

In North Dakota: TCR, ECR, Renewable Resource Cost Recovery and Generation Cost Recovery (GCR) riders.

●

In South Dakota: TCR, ECR, Phase-In Rate Plan and Energy Efficiency Plan (conservation) riders.

Following is a brief summary of recent proceedings of riders in place in each state served by OTP, followed by tables showing revenues recorded under rate riders for the three - and nine -month periods ended September 30, 2020 and September 30, 2019 and a listing of rate rider updates impacting revenues in 2020 and 2019. Additional information and background on these rate riders is provided in the Company’s Annual Report on Form 10 -K for the year ended December 31, 2019.

Minnesota

Minnesota Conservation Improvement Programs (MNCIP) —On May 1, 2020 OTP filed a request for approval of its 2019 energy savings, recovery of $ 2.7 million in accrued financial incentives and recovery of 2019 program costs not included in base rates. OTP’s request was approved by order of the MPUC on August 18, 2020.

Transmission Cost Recovery Rider —In OTP’s 2016 general rate case order issued on May 1, 2017, the MPUC ordered OTP to include, in the TCR Rider retail rate base, Minnesota’s jurisdictional share of OTP’s investment in the Big Stone South–Brookings and Big Stone South–Ellendale MVPs and all revenues received from other utilities under MISO’s tariffed rates as a credit in its TCR revenue requirement calculations. In doing so, the MPUC’s order diverted interstate wholesale revenues that have been approved by the FERC to offset FERC-approved expenses, effectively reducing OTP’s recovery of those FERC-approved expense levels. The MPUC-ordered treatment resulted in the projects being treated as retail investments for Minnesota retail ratemaking purposes. Because the FERC’s revenue requirements and authorized returns vary from the MPUC revenue requirements and authorized returns for the project investments over the lives of the projects, the impact of this decision can vary over time and be dependent on the differences between the revenue requirements and returns in the two jurisdictions at any given time. On August 18, 2017 OTP filed an appeal of the MPUC general rate case order with the Minnesota Court of Appeals to contest the portion of the order requiring OTP to jurisdictionally allocate costs of the FERC MVP transmission projects in the TCR Rider.

On June 11, 2018 the Minnesota Court of Appeals reversed the MPUC’s order related to the inclusion of Minnesota’s jurisdictional share of OTP’s investment in the Big Stone South–Brookings and Big Stone South–Ellendale MVPs and all revenues received from other utilities under MISO’s tariffed rates as a credit in OTP’s Minnesota TCR revenue requirement calculations. On July 11, 2018 the MPUC filed a petition for review of the MVP decision to the Minnesota Supreme Court, which granted review of the Minnesota Court of Appeals decision. The Minnesota Supreme Court issued its opinion on April 22, 2020, concluding the MPUC lacked authority to amend an existing transmission cost-recovery rider approved under Minnesota state law to include the costs and revenues associated with the Big Stone South–Brookings and Big Stone South–Ellendale MVPs and affirming the decision of the Minnesota Court of Appeals.

On October 22, 2020 the MPUC approved OTP’s request for a Minnesota TCR Rider update with exclusion of the Big Stone South–Brookings and Big Stone South–Ellendale projects and inclusion of three projects previously requested in the Minnesota TCR Rider eligibility petition. Updated rates go into effect in January 2021. With the decision, one -half of OTP’s Minnesota TCR December 2020 projected tracker balance of $ 13.4 million will be included in the 2021 TCR annual revenue requirement with the remainder included in the next annual update. The annual updates provide for recovery of approximately $ 2.6 million in excess MISO revenues credited to Minnesota customers through the TCR Rider prior to September 30, 2020. As a result, OTP recognized additional rider revenue of $ 2.6 million in the three -month period ended September 30, 2020.

Table of Contents

Renewable Resource Adjustment —On June 21, 2019 OTP filed its annual update to the Minnesota RRA requesting approval for recovery of the difference in PTCs in base rates and the actual PTCs generated, as well as recovery of Merricourt. On December 19, 2019 the MPUC approved a revised request which included changes related to Merricourt capitalized costs.

Fuel and Purchased Power Costs Recovery —In a December 2017 order, the MPUC adopted a program to implement certain procedural reforms to Minnesota utilities’ automatic fuel adjustment clause (FAC) for fuel and purchased power cost recovery. With this order, the method of accounting for all Minnesota electric utilities changed to a monthly budgeted, forward-looking FAC with annual prudence review and true-up to actual allowed costs. On October 31, 2019 the MPUC approved the forecasted monthly fuel cost rates submitted by OTP for 2020 and the rates became effective on January 1, 2020. This mechanism could result in reductions in Electric segment operating income margins, increase variability in consolidated net income in future periods if costs per kwh vary from forecasted costs per kwh, and cause an increase in working capital and short-term borrowings in the event recovery of all or a portion of excess costs is delayed or denied by the MPUC.

North Dakota

Renewable Resource Adjustment —On December 31, 2019 OTP filed its annual update to the North Dakota RRA requesting approval for recovery of the difference in PTCs in base rates and the actual PTCs generated, as well as a return on Merricourt costs incurred while under construction. This update also included a credit for the remaining unrefunded credit balance in the North Dakota ECR Rider tracker on November 30, 2019. On February 25, 2020 OTP filed a revised request which was approved by the NDPSC on March 18, 2020. Part of the NDPSC’s approval included adopting a levelized utilization of PTCs from the Merricourt project over the expected 25 -year life of the project for rate-making purposes. PTCs on prior projects were passed back to customers through lower rates as they were generated over 10 years.

Generation Cost Recovery Rider —On May 15, 2019 the NDPSC approved OTP’s request to establish an initial GCR Rider rate for recovery of OTP’s North Dakota jurisdictional share of the revenue requirements on its investment in Astoria Station, effective on bills rendered after July 1, 2019. On June 10, 2020 the NDPSC approved the 2020 annual update request with an effective date of July 1, 2020.

South Dakota

Phase-In Rate Plan Rider —On May 31, 2019 OTP petitioned the SDPUC for approval of its initial rate for the Phase-In Rate Plan Rider as described in OTP’s most recent South Dakota general rate case settlement stipulation and was approved by the SDPUC’s order in that rate case. The petition was OTP’s initial filing for the rider to recover OTP’s South Dakota share of actual and forecasted costs for Astoria Station and Merricourt, and to refund forecasted net benefits associated with additional load growth in the Lake Norden area. On August 6, 2020 the SDPUC approved OTP’s request for an updated Phase-In Rider Factor effective September 1, 2020.

Revenues Recorded under Rate Riders

The following table presents revenue recorded by OTP under rate riders in place in Minnesota, North Dakota, and South Dakota.

	Three Months Ended September 30,						Nine Months Ended September 30,
Rate Rider (in thousands)	2020			2019			2020			2019
Minnesota
Renewable Resource Recovery	$	3,318		$	1,316		$	9,660		$	3,949
Conservation Improvement Program Costs and Incentives		2,096			1,518			4,703			4,246
Transmission Cost Recovery		2,001			( 284	)		2,402			301
Environmental Cost Recovery		-			-			-			( 1	)
North Dakota
Renewable Resource Adjustment		1,256			( 20	)		3,455			616
Transmission Cost Recovery		809			908			3,131			3,554
Generation Cost Recovery		1,187			137			3,035			607
Environmental Cost Recovery		-			( 7	)		-			556
South Dakota
Transmission Cost Recovery		450			743			1,383			1,587
Conservation Improvement Program Costs and Incentives		194			100			748			440
Environmental Cost Recovery		-			( 2	)		-			( 29	)
Phase-In Rate Plan		( 53	)		( 10	)		( 77	)		( 10	)
Total	$	11,258		$	4,399		$	28,440		$	15,816

Table of Contents

Rate Rider Updates

The following table provides summary information on the status of updates since January 1, 2018 for the rate riders described above:

Rate Rider	R - Request Date A - Approval Date		Effective Date Requested or Approved	Annual Revenue *($000s)*			Rate
Minnesota
Conservation Improvement Program
2019 Incentive and Cost Recovery	A –	August 18, 2020	October 1, 2020	$	8,247		$ 0.00485	/kwh
2018 Incentive and Cost Recovery	A –	December 27, 2019	January 1, 2020	$	11,926		$ 0.00710	/kwh
2017 Incentive and Cost Recovery	A –	October 4, 2018	November 1, 2018	$	10,283		$ 0.00600	/kwh
Transmission Cost Recovery
2018 Annual Update–Updated Request	A –	October 22, 2020	January 1, 2021	$	10,260		Various
2017 Rate Reset	A –	October 30, 2017	November 1, 2017	$	( 3,311	)	Various
Environmental Cost Recovery
2018 Annual Update	A –	November 29, 2018	December 1, 2018	$	-		0 %	of base
Renewable Resource Adjustment
2019 Annual Update – Revised	A –	December 19, 2019	January 1, 2020	$	12,506		$ 0.00467	/kwh
2018 Annual Update	A –	August 29, 2018	November 1, 2018	$	5,886		$ 0.00219	/kwh
North Dakota
Renewable Resource Adjustment
2020 Annual Update	A –	March 18, 2020	April 1, 2020	$	5,762		5.637 %	of base
2019 Annual Update	A –	May 1, 2019	June 1, 2019	$	( 235	)	- 0.224 %	of base
2018 Rate Reset for effect of TCJA	A –	February 27, 2018	March 1, 2018	$	9,650		7.493 %	of base
Transmission Cost Recovery
2020 Annual Update	R –	August 31, 2020	January 1, 2021	$	5,570		Various
2019 Annual Update	A –	December 18, 2019	January 1, 2020	$	5,739		Various
2018 Supplemental Update	A –	December 6, 2018	February 1, 2019	$	4,801		Various
2018 Rate Reset for effect of TCJA	A –	February 27, 2018	March 1, 2018	$	7,469		Various
Environmental Cost Recovery
2019 Update	A –	October 22, 2019	November 1, 2019	$	-		0 %	of base
2018 Update	A –	December 19, 2018	February 1, 2019	$	( 378	)	- 0.310 %	of base
2018 Rate Reset for effect of TCJA	A –	February 27, 2018	March 1, 2018	$	7,718		5.593 %	of base
Generation Cost Recovery
2020 Annual Update	A –	June 10, 2020	July 1, 2020	$	6,184		6.041 %	of base
2019 Initial Request	A –	May 15, 2019	July 1, 2019	$	2,720		2.547 %	of base
South Dakota
Transmission Cost Recovery
2020 Annual Update	A –	February 19, 2020	March 1, 2020	$	2,327		Various
2019 Rate Reset	A –	September 17, 2019	October 1, 2019	$	2,046		Various
2019 Annual Update	A –	February 20, 2019	March 1, 2019	$	1,638		Various
2018 Interim Rate Reset	A –	October 18, 2018	October 18, 2018	$	1,171		Various
Environmental Cost Recovery
2018 Interim Rate Reset	A –	October 18, 2018	October 18, 2018	$	( 189	)	-$ 0.00075	/kwh
Phase-In Rate Plan Recovery
2020 Annual Update	A –	August 6, 2020	September 1, 2020	$	1,625		6.521 %	of base
2019 Initial Request	A –	August 21, 2019	September 1, 2019	$	864		3.345 %	of base

FERC

Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act of 1935 (Federal Power Act). The FERC is an independent agency with jurisdiction over rates for wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a suspension period, subject to ultimate approval by the FERC.

MVPs —MVPs are designed to enable the MISO region to comply with energy policy mandates and to address reliability and economic issues affecting multiple transmission zones within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit from the MVP.

Table of Contents

ROE —In November 2013 and February 2015, customers filed complaints with FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO tariff. OTP has deferred recognition and recorded a liability of $ 2.8 million as of September 30, 2020 as a result of the disputed ROE awaiting FERC action. The provision includes:

●

a $ 0.1 million refund for the first complaint period of November 2013 to February 2015 resulting from the potential reduction of the base ROE from 10.32 %.

●

a $ 1.4 million refund related to the second complaint period of February 2015 to May 2016 resulting from a potential reduction in base ROE from 12.38 %.

●

a $ 1.3 million refund for the period from September 2016 through September 2020 resulting from a potential reduction in base ROE from 10.82 %.

Various FERC orders have been made that remain under appeal. All or some of the current liability will be refunded to customers or reversed and recognized as revenue depending on various factors including MISO’s determination of refund amounts and FERC’s final determination of the reasonableness of base ROE over various periods.

Table of Contents

4. Regulatory Assets and Liabilities

As a regulated entity, OTP accounts for the financial effects of regulation in accordance with ASC 980. This accounting standard allows for the recording of a regulatory asset or liability for costs that will be collected or refunded in the future as required under regulation. Additionally, ASC 980 - 605 - 25 provides for the recognition of revenues authorized for recovery outside of a general rate case under alternative revenue programs which provide for recovery of costs and incentives or returns on investment in such items as transmission infrastructure, renewable energy resources or conservation initiatives. The following tables indicate the amount of regulatory assets and liabilities recorded on the Company’s consolidated balance sheets:

	September 30, 2020								Remaining Recovery/
(in thousands)	Current		Long-Term			Total				Refund Period (months)
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits ¹	$	9,018	$	122,765		$	131,783		see below
Minnesota Transmission Cost Recovery Rider Accrued Revenues ²		3,676		6,126			9,802			27
Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment ¹		-		8,481			8,481		asset lives
Conservation Improvement Program Costs and Incentives ²		1,040		2,094			3,134			24
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery ¹		-		2,149			2,149		asset lives
MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups ¹		1,234		559			1,793			27
Unrecovered Project Costs – Minnesota ¹		401		1,092			1,493			21
Minnesota Renewable Resource Rider Accrued Revenues ²		1,203		-			1,203			12
Unrecovered Project Costs – North Dakota ¹		-		856			856			21
Minnesota SPP Transmission Cost Recovery Tracker ¹		-		759			759		see below
Debt Reacquisition Premiums ¹		204		379			583			144
Unrecovered Project Costs – South Dakota ¹		144		357			501			24
South Dakota Deferred Rate Case Expenses Subject to Recovery ¹		137		143			280			25
North Dakota Deferred Rate Case Expenses Subject to Recovery ¹		122		152			274			27
Deferred Marked-to-Market Losses ¹		186		-			186			3
North Dakota Generation Cost Recovery Rider Accrued Revenue ²		66		-			66			9
Deferred Lease Expenses ¹		-		65			65			56
Minnesota Environmental Cost Recovery Rider Accrued Revenues ²		4		-			4			12
Total Regulatory Assets	$	17,435	$	145,977		$	163,412
Regulatory Liabilities:
Deferred Income Taxes	$	-	$	136,630		$	136,630		asset lives
Accumulated Reserve for Estimated Removal Costs – Net of Salvage		-		99,617			99,617		asset lives
Refundable Fuel Clause Adjustment Revenues		9,208		-			9,208			12
North Dakota Transmission Cost Recovery Rider Accrued Refund		1,233		-			1,233			3
South Dakota Phase-In Rate Plan Rider Accrued Refund		1,090		-			1,090			11
Revenue for Rate Case Expenses Subject to Refund – Minnesota		-		577			577		see below
Prior Service Costs and Actuarial Gains on Postretirement Benefits		471		-			471			12
North Dakota Renewable Resource Recovery Rider Accrued Refund		444		-			444			6
South Dakota Transmission Cost Recovery Rider Accrued Refund		232		-			232			5
Minnesota Energy Intensive Trade Exposed Rider Accrued Refund		186		-			186			12
Other		6		68			74			159
Total Regulatory Liabilities	$	12,870	$	236,892		$	249,762
Net Regulatory Asset/(Liability) Position	$	4,565	$	( 90,915	)	$	( 86,350	)

¹ Costs subject to recovery without a rate of return.

² Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

Table of Contents

	December 31, 2019								Remaining Recovery/
(in thousands)	Current		Long-Term			Total			Refund Period (months)
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits ¹	$	9,090	$	129,102		$	138,192		see below
Minnesota Transmission Cost Recovery Rider Accrued Revenues ²		4,208		-			4,208			12
Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment ¹		-		7,772			7,772		asset lives
Conservation Improvement Program Costs and Incentives ²		4,024		2,844			6,868			21
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery ¹		-		1,681			1,681		asset lives
MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups ¹		2,033		968			3,001			24
Unrecovered Project Costs – Minnesota ¹		715		225			940			16
Minnesota Renewable Resource Rider Accrued Revenues ²		131		-			131			12
Minnesota SPP Transmission Cost Recovery Tracker ¹		-		202			202		see below
Debt Reacquisition Premiums ¹		201		548			749			153
Unrecovered Project Costs – South Dakota ¹		144		253			397			33
South Dakota Deferred Rate Case Expenses Subject to Recovery ¹		138		245			383			34
North Dakota Deferred Rate Case Expenses Subject to Recovery ¹		122		244			366			36
Deferred Marked-to-Market Losses ¹		743		-			743			12
Deferred Lease Expenses ¹		-		54			54			39
Minnesota Environmental Cost Recovery Rider Accrued Revenues ²		4		-			4			12
South Dakota Transmission Cost Recovery Rider Accrued Revenues ²		97		-			97			2
Total Regulatory Assets	$	21,650	$	144,138		$	165,788
Regulatory Liabilities:
Deferred Income Taxes	$	-	$	141,707		$	141,707		asset lives
Accumulated Reserve for Estimated Removal Costs – Net of Salvage		-		97,726			97,726		asset lives
Refundable Fuel Clause Adjustment Revenues		3,982		-			3,982			12
North Dakota Transmission Cost Recovery Rider Accrued Refund		700		-			700			12
South Dakota Phase-In Rate Plan Rider Accrued Refund		355		-			355			9
Revenue for Rate Case Expenses Subject to Refund – Minnesota		-		401			401		see below
Prior Service Costs and Actuarial Gains on Postretirement Benefits		471		-			471			12
North Dakota Renewable Resource Recovery Rider Accrued Refund		1,515		-			1,515			12
Minnesota Energy Intensive Trade Exposed Rider Accrued Refund		164		-			164			12
North Dakota Generation Cost Recovery Rider Accrued Refund		287		-			287			6
Other		6		72			78			168
Total Regulatory Liabilities	$	7,480	$	239,906		$	247,386
Net Regulatory Asset/(Liability) Position	$	14,170	$	( 95,768	)	$	( 81,598	)

¹ Costs subject to recovery without a rate of return.

² Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

The regulatory asset and liability related to prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses and gains subject to recovery or refund through rates as they are expensed. These unrecognized benefit costs and actuarial losses and gains are required to be recognized as components of Accumulated Other Comprehensive Income in equity under ASC Topic 715, Compensation—Retirement Benefits , but are eligible for treatment as regulatory assets or liabilities based on their probable inclusion in future retail electric rates.

The Minnesota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities and operating costs incurred to serve Minnesota customers that were recoverable from Minnesota customers as of the balance sheet date.

The Accumulated ARO Accretion/Depreciation Adjustment will accrete and be amortized over the lives of property with asset retirement obligations.

Conservation Improvement Program Costs and Incentives represent mandated conservation expenditures and incentives recoverable through retail electric rates.

Table of Contents

The Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery are employee benefit-related costs that are required to be capitalized for ratemaking purposes and are recovered over the depreciable lives of the assets to which the related labor costs were applied.

MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups relate to the over/under collection of revenue based on comparison of the expected versus actual construction on eligible projects in the period. The true-ups also include the state jurisdictional portion of MISO Schedule 26/26A for regional transmission cost recovery that was included in the calculation of the state transmission riders and subsequently adjusted to reflect actual billing amounts in the schedule.

Unrecovered Project Costs – Minnesota are the Minnesota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project and excess unrecovered depreciation expense for Hoot Lake Plant and OTP’s hydroelectric plants related to acceleration of their remaining depreciable lives.

The Minnesota Renewable Resource Recovery Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that were recoverable from Minnesota customers as of the balance sheet date.

Unrecovered Project Costs – North Dakota are the North Dakota share of excess unrecovered depreciation expense for Hoot Lake Plant and OTP’s hydroelectric plants related to acceleration of their remaining depreciable lives.

The Minnesota SPP Transmission Cost Recovery Tracker regulatory asset relates to costs incurred to serve Minnesota customers that are subject to recovery but that had not been billed to Minnesota customers as of the balance sheet date.

Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 147 months.

Unrecovered Project Costs – South Dakota are the South Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project and excess unrecovered depreciation expense for Hoot Lake Plant and OTP’s hydroelectric plants related to acceleration of their remaining depreciable lives.

South Dakota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s most recent rate case in South Dakota and are currently being recovered beginning with the establishment of interim rates in October 2018.

North Dakota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s most recent rate case in North Dakota currently being recovered beginning with the establishment of interim rates in January 2018.

All Deferred Marked-to-Market Losses recorded as of the balance sheet date relate to forward purchases of energy scheduled for delivery through December 2020.

The North Dakota Generation Cost Recovery Rider Accrued Revenues relate to revenues earned under the rider on recoverable costs incurred for the North Dakota share of OTP’s investment in Astoria Station, a natural gas-fired combustion turbine generation facility under construction near Astoria, South Dakota. The balance represents amounts subject to recovery from North Dakota customers that had not been billed to North Dakota customers as of the balance sheet date.

Deferred Lease Expenses: Under ASC 842 accounting rules for leases with scheduled escalating payments, rent expense is required to be recognized on a straight-line basis over the life of the lease based on the sum of those payments. Rate-regulated entities are generally only allowed to recover the amount of actual cash payments on leases and FERC accounting rules require that rent expense be recognized on the basis of cash payments. The balance in the deferred lease expense regulatory asset account represents operating lease right of use asset cumulative amortization and interest costs in excess of cumulative lease payments that are subject to recovery in future periods under regulatory accounting treatment as cash payments are rendered.

The Minnesota Environmental Cost Recovery Rider Accrued Revenues relate to revenues earned on the Minnesota share of OTP’s investment in the Big Stone Plant AQCS project that were recoverable from Minnesota customers as of the balance sheet date.

The South Dakota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities and operating costs incurred to serve South Dakota customers that were recoverable from South Dakota customers as of the balance sheet date.

The regulatory liability related to Deferred Income Taxes results from changes in statutory tax rates accounted for in accordance with ASC Topic 740, Income Taxes .

Table of Contents

The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred.

The North Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve North Dakota customers that were refundable to North Dakota customers as of the balance sheet date.

The South Dakota Phase-In Rate Plan Rider Accrued Refund relates to amounts collected for actual and forecasted costs for Astoria Station, Merricourt, and additional load growth that were refundable to South Dakota customers as of the balance sheet date.

Revenue for Rate Case Expenses Subject to Refund – Minnesota relates to revenues collected under general rates to recover costs related to prior rate case proceedings in excess of the actual costs incurred.

The North Dakota Renewable Resource Recovery Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve North Dakota customers that were refundable to North Dakota customers as of the balance sheet date.

The South Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve South Dakota customers that were refundable to South Dakota customers as of the balance sheet date.

The Minnesota Energy Intensive Trade Exposed Rider Accrued Refund relates to over-collected amounts from Minnesota retail customers for fuel and purchased power costs reductions provided to customers in energy intensive trade exposed industries that were subject to refund to Minnesota customers as of the balance sheet date.

The North Dakota Generation Cost Recovery Rider Accrued Refund relates to revenues collected under the rider in excess of returns allowed on recoverable costs incurred for the North Dakota share of OTP’s investment in Astoria Station, a natural gas-fired combustion turbine generation facility under construction near Astoria, South Dakota. The balance represents amounts subject to refund to North Dakota customers that had been billed to North Dakota customers as of the balance sheet date.

If for any reason OTP ceases to meet the criteria for application of guidance under ASC 980 for all or part of its operations, the regulatory assets and liabilities that no longer meet such criteria would be removed from the consolidated balance sheet and included in the consolidated statement of income as an expense or income item in the period in which the application of guidance under ASC 980 ceases.

5. Common Shares and Earnings Per Share

Shelf Registration

On May 3, 2018 the Company filed a shelf registration statement with the Securities and Exchange Commission (SEC) under which the Company may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, which expires on May 3, 2021.

On November 8, 2019, the Company entered into a Distribution Agreement with KeyBanc Capital Markets Inc. (KeyBanc Capital Markets). Pursuant to the terms of the Distribution Agreement, the Company may offer and sell its common shares from time to time through KeyBanc, as the Company’s distribution agent for the offer and sale of the shares, up to an aggregate sales price of $ 75,000,000 .

Under the Distribution Agreement, the Company will designate the minimum price and maximum number of common shares to be sold through KeyBanc on any given trading day or over a specified period of trading days, and KeyBanc will use commercially reasonable efforts to sell such shares on such days, subject to certain conditions. Sales of the shares, if any, will be made by means of ordinary brokers’ transactions on the Nasdaq Global Select Market at market prices or as otherwise agreed with KeyBanc. The Company may also agree to sell shares to KeyBanc, as principal for its own account, on terms agreed to by the Company and KeyBanc in a separate agreement at the time of sale. KeyBanc will receive from the Company a commission of up to 2 % of the gross sales price per share for any shares sold through it as the Company’s distribution agent under the Distribution Agreement. The Company is not obligated to sell and KeyBanc is not obligated to buy or sell any of the shares under the Distribution Agreement. The shares, if issued, will be issued pursuant to the Company’s existing shelf registration statement.

Table of Contents

2020 Common Stock Activity

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2019 through September 30, 2020:

Common Shares Outstanding, December 31, 2019	40,157,591
Issuances:
At-the-Market Offering	588,084
Automatic Dividend Reinvestment and Share Purchase Plan:
Dividends Reinvested	102,042
Cash Invested	88,636
Executive Stock Performance Awards (2017 awards earned)	62,497
Vesting of Restricted Stock Units	35,720
Employee Stock Purchase Plan:
Cash Invested	29,894
Dividends Reinvested	7,906
Restricted Stock Issued to Directors	17,400
Directors Deferred Compensation	612
Retirements:
Shares Withheld for Individual Income Tax Requirements	( 38,217	)
Common Shares Outstanding, September 30, 2020	41,052,165

Earnings Per Share

The numerator used in the calculation of both basic and diluted earnings per common share is net income with no adjustments for the three - and nine -month periods ended September 30, 2020 and 2019. The denominator used in the calculation of basic earnings per common share is the weighted average number of common shares outstanding during the period excluding nonvested restricted shares granted to the Company’s directors, which are considered contingently returnable and not outstanding for the purpose of calculating basic earnings per share. The denominator used in the calculation of diluted earnings per common share is derived by adjusting basic shares outstanding for the items listed in the following reconciliation for the three - and nine -month periods ended September 30:

	Three Months ended September 30				Nine Months ended September 30
	2020		2019		2020		2019
Weighted Average Common Shares Outstanding – Basic		40,913,972		39,714,672		40,548,133		39,694,677
Plus Outstanding Share Awards net of Share Reductions for Unrecognized Stock-Based Compensation Expense and Excess Tax Benefits:
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers based on Measurement Period-to-Date Performance		98,012		149,023		107,017		147,106
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees		48,682		68,138		53,303		63,902
Shares Expected to be Issued Under the Employee Stock Purchase Plan		13,182		-		14,997		-
Nonvested Restricted Shares		2,603		13,107		8,033		14,896
Shares Expected to be Issued Under the Deferred Compensation Program for Directors		1,238		1,799		1,445		1,999
Total Dilutive Shares		163,717		232,067		184,795		227,903
Weighted Average Common Shares Outstanding – Diluted		41,077,689		39,946,739		40,732,928		39,922,580

Table of Contents

6. Share-Based Payments

Stock Incentive Awards

The following stock incentive awards were granted under the 2014 Stock Incentive Plan during the nine months ended September 30, 2020.

Award	Grant Date	Shares/ Units Granted		Weighted Average Grant-Date Fair Value per Award		Vesting
Restricted Stock Units Granted:
With Dividend Equivalent:
To Key Management Employees	February 3, 2020		3,000	$	54.0450	25% per year through February 6, 2024
To Executive Officers	February 12, 2020		15,300	$	54.0607	25% per year through February 6, 2024
Without Dividend Equivalent:
To Nonexecutive Employees	April 20, 2020		14,975	$	40.18	100% April 8, 2024
Stock Performance Awards Granted:
Under Executive Agreement	February 12, 2020		47,600	$	47.10	December 31, 2022
Under Legacy Agreement	February 12, 2020		7,400	$	52.20	December 31, 2022
Restricted Stock Granted to Nonemployee Directors	April 20, 2020		17,400	$	44.85	33% per year through April 8, 2023

The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement, subject to proration in certain cases, and subject to forfeiture under the terms of the restricted stock unit award agreements. Certain restricted stock units granted to executive officers and certain key employees are eligible to receive dividend equivalent payments on all unvested awards over the awards respective vesting periods. The grant-date fair value of each restricted stock unit paying a dividend equivalent was the average of the high and low market price per share on the date of grant. The grant-date fair value of each restricted stock unit that does not pay a dividend equivalent was the average of the high and low market price per share on the date of grant, discounted for the value of the dividend exclusion on those restricted stock units over the unit’s vesting period.

Under the performance share awards the aggregate award for performance at target is 55,000 shares. For target performance the participants would earn an aggregate of 27,500 common shares for achieving the target set for the Company’s 3 -year average adjusted ROE. The participants would also earn an aggregate of 27,500 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the Edison Electric Institute Index over the performance measurement period of January 1, 2020 through December 31, 2022, with the beginning and ending share values based on the average closing price of a share of the Company’s common stock for the 20 trading days immediately following January 1, 2020 and the average closing price for the 20 trading days immediately preceding January 1, 2023. Actual payment may range from zero to 150 % of the target amount, or up to 82,500 common shares. There are no voting or dividend rights related to these shares until the shares, if any, are issued at the end of the performance measurement period. The terms of these awards are such that the entire award will be classified and accounted for as equity, as required under ASC 718, Compensation – Stock Compensation , and will be measured over the performance period based on the grant-date fair value of the award. The grant-date fair value of each performance share award was determined using a Monte Carlo fair valuation simulation model.

Under the 2020 Performance Award Agreements, payment and the amount of payment in the event of retirement, resignation for good reason or involuntary termination without cause is to be made at the end of the performance period based on actual performance, subject to proration in certain cases, except that the payment of performance awards granted to an officer who is party to an Executive Employment Agreement with the Company is to be made at target at the date of any such event. The vesting of these awards is accelerated and paid at target in the event of a change in control.

The restricted shares granted to the Company’s nonemployee directors are eligible for full dividend and voting rights. Restricted shares not vested and dividends on those restricted shares are subject to forfeiture under the terms of the restricted stock award agreements. The grant-date fair value of each restricted share was the average of the high and low market price per share on the date of grant.

The end of the period over which compensation expense is recognized for the above share-based awards for the individual grantees is the earlier of the indicated vesting period for the respective awards or the date the grantee becomes eligible for retirement as defined in their award agreement.

Table of Contents

As of September 30, 2020, the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $ 3.9 million (before income taxes) which will be amortized over a weighted-average period of 1.9 years.

Amounts of compensation expense recognized under the Company’s stock-based payment programs for the three - and nine -month periods ended September 30, 2020 and 2019 are presented in the table below:

	Three months ended				Nine months ended
	September 30,				September 30,
(in thousands)	2020		2019		2020		2019
Stock Performance Awards Granted to Executive Officers	$	758	$	743	$	3,170	$	3,274
Restricted Stock Dividend Equivalent Units Granted to Executive Officers and Key Employees		106		189		891		999
Restricted Stock Granted to Nonemployee Directors		237		203		677		572
Restricted Stock Units Granted to Nonexecutive Employees		133		112		408		346
ESPP (15% discount)		41		54		136		54
Totals	$	1,275	$	1,301	$	5,282	$	5,245

7. Retained Earnings and Dividend Restriction

The Company is a holding company with no significant operations of its own. The primary source of funds for payments of dividends to the Company’s shareholders is from dividends paid or distributions made by the Company’s subsidiaries. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by the Company’s subsidiaries.

Both the Company and OTP credit agreements contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be considered to have occurred if the Company did not meet certain financial covenants. As of September 30, 2020, the Company was in compliance with these financial covenants.

Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. What constitutes “funds properly included in a capital account” is undefined in the Federal Power Act or the related regulations; however, the FERC has consistently interpreted the provision to allow dividends to be paid as long as ( 1 ) the source of the dividends is clearly disclosed, ( 2 ) the dividend is not excessive and ( 3 ) there is no self-dealing on the part of corporate officials.

The MPUC indirectly limits the amount of dividends OTP can pay to the Company by requiring an equity-to-total-capitalization ratio between 47.5 % and 58.1 % based on OTP’s 2020 capital structure petition effective by order of the MPUC on July 15, 2020. As of September 30, 2020, OTP’s equity-to-total-capitalization ratio including short-term debt was 52.8 % and its net assets restricted from distribution totaled approximately $ 619 million. Under the 2020 capital structure petition, OTP’s total capitalization cannot exceed $ 1,704,607,000 .

8. Leases

No update required for interim reporting periods.

9. Commitments and Contingencies

Construction and Other Purchase Commitments

At September 30, 2020 OTP had commitments under contracts, including its share of construction program commitments and other commitments, extending into 2022 of approximately $ 58 million. At December 31, 2019 OTP had commitments under contracts, including its share of construction program commitments and other nonlease commitments, extending into 2021 of approximately $ 317 million.

On October 1, 2019 T.O. Plastics entered into a six -year resin supply agreement that commenced on January 1, 2020. Under the resin supply agreement, there are no minimum purchase requirements, but T.O. Plastics is required to purchase all of a specified class of regrind resin delivered by the supplier at a set price per pound. Based on current forecasted production levels, T.O. Plastics anticipates the quantity of resin delivered under the supply agreement will not exceed its requirements over the six -year term of the supply agreement or exceed the market cost of alternative sources of the resin. T.O. Plastics estimates it will pay the supplier approximately $ 1.9 million annually under this agreement.

Table of Contents

Electric Utility Capacity and Energy Requirements and Coal Purchase and Delivery Contracts

OTP has commitments for the purchase of capacity and energy requirements under agreements extending into 2043. OTP also has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. OTP’s current coal purchase agreements for Coyote Station expire at the end of 2040. OTP has agreements with Peabody COALSALES, LLC (Peabody) for the purchase of subbituminous coal for Big Stone Plant’s coal requirements through December 31, 2022. There are no fixed minimum purchase requirements under these agreements but all of Big Stone Plant’s coal requirements for the period covered must be purchased exclusively from Peabody. OTP has an all-requirements agreement with Navajo Transitional Energy Co. for the purchase of subbituminous coal for Hoot Lake Plant through December 31, 2023, with no fixed minimum purchase requirement. OTP plans to discontinue generation at Hoot Lake Plant in May 2021.

OTP Land Easements

OTP has commitments to make future payments for land easements not classified as leases, extending into 2034 of approximately $ 9.7 million.

Transmission Obligation

In September 2020, in connection with Merricourt and in accordance with the Merricourt amended and restated generator interconnection agreement, OTP entered into a 20 -year Facilities Service Agreement (FSA) with an owner of adjacent transmission assets to pay for upgrades and additions to the owner’s transmission facilities required to accommodate the transmission of electricity generated by Merricourt’s wind turbines. OTP estimates it will pay approximately $ 675,000 annually through October 2040 under the FSA. The annual payment requirements are subject to adjustments for changes in income tax rates, rates of return on assets and other variable factors included in the MISO tariff.

Contingencies

OTP had a $ 2.8 million refund liability on its balance sheet as of September 30, 2020. This represents its best estimate of the refund obligations that would arise net of amounts that would be subject to recovery under state jurisdictional TCR riders. This is based on the outcome of the appeals of the FERC ruling reducing the ROE component of the MISO Tariff and ordering MISO to refund amounts charged in excess of the lower rate. As discussed in note 3 in greater detail, OTP believes its estimated accrued refund liability is appropriate based on the current facts and circumstances and is awaiting results of the appeal before determining if a change in this estimate will be needed.

Contingencies, by their nature, relate to uncertainties that require the Company’s management to exercise judgment both in assessing the likelihood a liability has been incurred as well as in estimating the amount of potential loss. In addition to the potential ROE refund described above, the most significant contingencies that could impact the Company’s consolidated financial statements are those related to environmental remediation, risks associated with warranty claims relating to divested businesses that could exceed established reserve amounts, risks associated with adverse regulatory decisions that could impact the recovery of fixed asset costs in future rates and litigation matters.

On July 30, 2020 the MPUC ordered a reduction in the remaining depreciable lives of OTP’s Hoot Lake Plant and seven hydroelectric plants. The MPUC stipulated recoverability of the resulting increase in depreciation expense, which we estimate will be approximately $ 1.4 million on an annual basis, would be determined in OTP’s next rate case. Based on the relevant facts and circumstances, OTP has concluded the additional depreciation expense is probable of recovery and has recognized a regulatory asset for the amount of incremental expense recognized in 2020.

State implementation of pollution control plans to improve visibility and air quality at national parks under the EPA’s Regional Haze Rule (RHR) could require OTP to incur significant new costs, which could, dependent on determinations by state regulatory commissions on approval to recover such costs from customers, negatively impact OTP’s and the Company’s net income, financial position and cash flows. The North Dakota Department of Environmental Quality (NDDEQ) must submit a state implementation plan to the EPA by July 2021. While this process is still in the early stages, if the NDDEQ and/or the EPA requires sources subject to RHR Round 2 reasonable progress determinations, including Coyote Station, to undertake emissions control measures that are reasonably consistent with those required of sources during Round 1, OTP anticipates that significant emissions controls would be required at Coyote Station by December 31, 2028. In light of the costs for emissions control equipment, there are scenarios where it may not be economically feasible to invest in such equipment and an early retirement of the Coyote Station would therefore be necessary. The costs related to an early retirement of Coyote Station would be material to OTP and the Company and would be subject to state commission approval for recovery from customers.

In October 2020, during testing and commissioning of Merricourt, a defect in a turbine blade was identified. The Company is investigating the defect along with additional blades to determine if other blades have similar defects. Depending on the extent of the defect and repair and replacement alternatives, the date of commercial operation of the project, or a portion thereof, may be delayed beyond December 2020. The cost of the project could also be impacted, but the risk of loss on assets of the project only transfers to Otter Tail Power Company at commercial operation. Considering this along with the commercial and contractual provisions in place, the Company does not anticipate this issue will have a material financial impact on the Company.

Table of Contents

Other

The Company is a party to litigation and regulatory enforcement matters arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of September 30, 2020, other than those relating to the RHR, will not be material.

10. Short-Term and Long-Term Borrowings

The following table presents the status of the Company’s lines of credit as of September 30, 2020 and December 31, 2019:

(in thousands)	Line Limit		In Use on September 30, 2020		Restricted due to Outstanding Letters of Credit		Available on September 30, 2020		Available on December 31, 2019
Otter Tail Corporation Credit Agreement	$	170,000	$	48,600	$	-	$	121,400	$	164,000
OTP Credit Agreement		170,000		-		7,670		162,330		154,524
Total	$	340,000	$	48,600	$	7,670	$	283,730	$	318,524

Long-Term Debt Issuances

2019 Note Purchase Agreement

On September 12, 2019, OTP entered into a Note Purchase Agreement (the 2019 Note Purchase Agreement) with the purchasers named therein (the Purchasers), pursuant to which OTP agreed to issue to the Purchasers, in a private placement transaction, $ 175 million aggregate principal amount of OTP’s senior unsecured notes consisting of (a) $ 10,000,000 aggregate principal amount of its 3.07 % Series 2019A Senior Unsecured Notes due October 10, 2029 ( the Series 2019A Notes), (b) $ 26,000,000 aggregate principal amount of its 3.52 % Series 2019B Senior Unsecured Notes due October 10, 2039 ( the Series 2019B Notes), (c) $ 64,000,000 aggregate principal amount of its 3.82 % Series 2019C Senior Unsecured Notes due October 10, 2049 ( the Series 2019C Notes), (d) $ 10,000,000 aggregate principal amount of its 3.22 % Series 2020A Senior Unsecured Notes due February 25, 2030 ( the Series 2020A Notes), (e) $ 40,000,000 aggregate principal amount of its 3.22 % Series 2020B Senior Unsecured Notes due August 20, 2030 ( the Series 2020B Notes), (f) $ 10,000,000 aggregate principal amount of its 3.62 % Series 2020C Senior Unsecured Notes due February 25, 2040 ( the Series 2020C Notes) and (g) $ 15,000,000 aggregate principal amount of its 3.92 % Series 2020D Senior Unsecured Notes due February 25, 2050 ( the Series 2020D Notes; and together with the Series 2019A Notes, the Series 2019B Notes, the Series 2019C Notes, the Series 2020A Notes, the Series 2020B Notes and the Series 2020C Notes, the Notes).

On February 25, 2020, OTP issued the Series 2020A Notes, the Series 2020C Notes and the Series 2020D Notes pursuant to the 2019 Note Purchase Agreement. On August 20, 2020, OTP issued the Series 2020B Notes pursuant to the 2019 Note Purchase Agreement. OTP used the $ 75 million proceeds from the issuances to pay for capital expenditures and for other corporate purposes. The Series 2019A Notes, Series 2019B Notes and Series 2019C Notes were issued by the Company on October 10, 2019.

OTP may prepay all or any part of the Notes (in an amount not less than 10 % of the aggregate principal amount of the Notes then outstanding in the case of a partial prepayment) at 100 % of the principal amount so prepaid, together with unpaid accrued interest and a make-whole amount; provided that if no default or event of default exists under the 2019 Note Purchase Agreement, any prepayment made by OTP of all of the (a) Series 2020A Notes then outstanding on or after August 25, 2029, (b) Series 2020C Notes then outstanding on or after August 25, 2039 or (c) Series 2020D Notes then outstanding on or after August 25, 2049 will be made without any make-whole amount. The 2019 Note Purchase Agreement also requires OTP to offer to prepay all outstanding Notes at 100% of the principal amount together with unpaid accrued interest in the event of a Change of Control (as defined in the 2019 Note Purchase Agreement) of OTP.

The 2019 Note Purchase Agreement contains a number of restrictions on the business of OTP. These include restrictions on OTP’s abilities to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The 2019 Note Purchase Agreement also contains other negative covenants and events of default, as well as certain financial covenants. Specifically, OTP may not permit its Interest-bearing Debt (as defined in the 2019 Note Purchase Agreement) to exceed 60 % of Total Capitalization (as defined in the 2019 Note Purchase Agreement), determined as of the end of each fiscal quarter. OTP is also restricted from allowing its Priority Indebtedness (as defined in the Note Purchase Agreement) to exceed 20 % of Total Capitalization, determined as of the end of each fiscal quarter. The 2019 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. The 2019 Note Purchase Agreement includes a “most favored lender” provision generally requiring that in the event OTP’s existing credit agreement or any renewal, extension or replacement thereof, at any time contains any financial covenant or other provision providing for limitations on interest

Table of Contents

expense and such a covenant is not contained in the 2019 Note Purchase Agreement under substantially similar terms or would be more beneficial to the holders of the Notes than any analogous provision contained in the 2019 Note Purchase Agreement (an Additional Covenant), then unless waived by the Required Holders (as defined in the 2019 Note Purchase Agreement), the Additional Covenant will be deemed to be incorporated into the 2019 Note Purchase Agreement. The 2019 Note Purchase Agreement also provides for the amendment, modification or deletion of an Additional Covenant if such Additional Covenant is amended or modified under or deleted from the credit agreement, provided that no default or event of default has occurred and is continuing.

The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of September 30, 2020 and December 31, 2019:

September 30 , 2020 (in thousands)	OTP		Otter Tail Corporation		Consolidated
Short-Term Debt	$	-	$	48,600	$	48,600
Long-Term Debt:
3.55% Guaranteed Senior Notes, due December 15, 2026			$	80,000	$	80,000
Senior Unsecured Notes 4.63%, Series 2011A, due December 1, 2021	$	140,000				140,000
Senior Unsecured Notes 6.15%, Series 2007B, due August 20, 2022		30,000				30,000
Senior Unsecured Notes 6.37%, Series 2007C, due August 20, 2027		42,000				42,000
Senior Unsecured Notes 4.68%, Series 2013A, due February 27, 2029		60,000				60,000
Senior Unsecured Notes 3.07%, Series 2019A, due October 10, 2029 ¹		10,000				10,000
Senior Unsecured Notes 3.22%, Series 2020A, due February 25, 2030		10,000				10,000
Senior Unsecured Notes 3.22%, Series 2020B, due August 20, 2030 ¹		40,000				40,000
Senior Unsecured Notes 6.47%, Series 2007D, due August 20, 2037		50,000				50,000
Senior Unsecured Notes 3.52%, Series 2019B, due October 10, 2039		26,000				26,000
Senior Unsecured Notes 3.62%. Series 2020C, due February 25, 2040		10,000				10,000
Senior Unsecured Notes 5.47%, Series 2013B, due February 27, 2044		90,000				90,000
Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048		100,000				100,000
Senior Unsecured Notes 3.82%, Series 2019C, due October 10, 2049		64,000				64,000
Senior Unsecured Notes 3.92%, Series 2020D, due February 25, 2050		15,000				15,000
PACE Note, 2.54%, due March 18, 2021				215		215
Total	$	687,000	$	80,215	$	767,215
Less: Current Maturities net of Unamortized Debt Issuance Costs		-		215		215
Unamortized Long-Term Debt Issuance Costs		2,408		318		2,726
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	684,592	$	79,682	$	764,274
Total Short-Term and Long-Term Debt (with current maturities)	$	684,592	$	128,497	$	813,089
December 31, 2019 (in thousands)
Short-Term Debt	$	-	$	6,000	$	6,000
Long-Term Debt:
3.55% Guaranteed Senior Notes, due December 15, 2026			$	80,000	$	80,000
Senior Unsecured Notes 4.63%, Series 2011A, due December 1, 2021	$	140,000				140,000
Senior Unsecured Notes 6.15%, Series 2007B, due August 20, 2022		30,000				30,000
Senior Unsecured Notes 6.37%, Series 2007C, due August 20, 2027		42,000				42,000
Senior Unsecured Notes 4.68%, Series 2013A, due February 27, 2029		60,000				60,000
Senior Unsecured Notes 3.07%, Series 2019A, due October 10, 2029 ¹		10,000				10,000
Senior Unsecured Notes 6.47%, Series 2007D, due August 20, 2037		50,000				50,000
Senior Unsecured Notes 3.52%, Series 2019B, due October 10, 2039		26,000				26,000
Senior Unsecured Notes 5.47%, Series 2013B, due February 27, 2044		90,000				90,000
Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048		100,000				100,000
Senior Unsecured Notes 3.82%, Series 2019C, due October 10, 2049		64,000				64,000
PACE Note, 2.54%, due March 18, 2021				351		351
Total	$	612,000	$	80,351	$	692,351
Less: Current Maturities net of Unamortized Debt Issuance Costs		-		183		183
Unamortized Long-Term Debt Issuance Costs		2,231		356		2,587
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	609,769	$	79,812	$	689,581
Total Short-Term and Long-Term Debt (with current maturities)	$	609,769	$	85,995	$	695,764

¹ Holder is COBANK, a cooperative lender. Interest payments are subject to cash credits which may result in a lower effective interest rate.

Table of Contents

1 1 . Pension Plan and Other Postretirement Benefits

Pension Plan —Components of net periodic pension benefit cost of the Company's noncontributory funded pension plan are as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2020			2019			2020			2019
Service Cost—Benefit Earned During the Period	$	1,655		$	1,373		$	4,966		$	4,119
Interest Cost on Projected Benefit Obligation		3,264			3,603			9,790			10,809
Expected Return on Assets		( 5,506	)		( 5,324	)		( 16,516	)		( 15,973	)
Amortization of Prior-Service Cost:
From Regulatory Asset		-			1			-			4
From Other Comprehensive Income ¹		-			2			-			6
Amortization of Net Actuarial Loss:
From Regulatory Asset		2,231			1,163			6,693			3,488
From Other Comprehensive Income ¹		55			26			165			79
Net Periodic Pension Cost ²	$	1,699		$	844		$	5,098		$	2,532
¹ Corporate cost included in nonservice cost components of postretirement benefits.
² Allocation of costs:
Service costs included in OTP capital expenditures	$	516		$	333		$	1,371		$	1,059
Service costs included in electric operation and maintenance expenses		1,099			1,007			3,476			2,961
Service costs included in other nonelectric expenses		40			33			119			99
Nonservice costs capitalized as regulatory assets		13			( 128	)		36			( 408	)
Nonservice costs included in n onservice cost components of postretirement benefits		31			( 401	)		96			( 1,179	)

Cash flows —The Company had no minimum funding requirement as of December 31, 2019 but made a discretionary plan contribution of $ 11.2 million in January 2020.

Executive Survivor and Supplemental Retirement Plan —Components of net periodic pension benefit cost of the Company’s unfunded, nonqualified benefit plan for executive officers and certain key management employees are as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2020		2019		2020		2019
Service Cost—Benefit Earned During the Period	$	45	$	104	$	134	$	313
Interest Cost on Projected Benefit Obligation		362		433		1,086		1,301
Amortization of Prior Service Cost:
From Regulatory Asset		-		2		-		4
From Other Comprehensive Income ¹		-		4		-		12
Amortization of Net Actuarial Loss:
From Regulatory Asset		24		31		71		93
From Other Comprehensive Income ¹		85		87		256		262
Net Periodic Pension Cost ²	$	516	$	661	$	1,547	$	1,985
¹ Amortization of prior service costs and net actuarial losses from other comprehensive income are included in n onservice cost components of postretirement benefits.
² Allocation of Costs:
Service costs included in electric operation and maintenance expenses	$	-	$	26	$	-	$	78
Service costs included in other nonelectric expenses		45		78		134		235
Nonservice costs included in n onservice cost components of postretirement benefits		471		557		1,413		1,672

Table of Contents

Other Postretirement Benefits —Components of net periodic postretirement benefit cost for health insurance benefits for retired OTP and corporate employees, net of the effect of Medicare Part D Subsidy:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2020			2019			2020			2019
Service Cost—Benefit Earned During the Period	$	461		$	321		$	1,385		$	964
Interest Cost on Projected Benefit Obligation		598			770			1,795			2,312
Amortization of Prior-Service Cost:
From Regulatory Asset		( 1,169	)		-			( 3,508	)		-
From Other Comprehensive Income ¹		( 28	)		-			( 86	)		-
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,051			393			3,154			1,178
From Other Comprehensive Income ¹		26			10			78			29
Net Periodic Postretirement Benefit Cost ²	$	939		$	1,494		$	2,818		$	4,483
Effect of Medicare Part D Subsidy	$	281		$	( 45	)	$	842		$	( 134	)
¹ Corporate cost included in nonservice cost components of postretirement benefits.
² Allocation of Costs:
Service costs included in OTP capital expenditures	$	144		$	78		$	382		$	248
Service costs included in electric operation and maintenance expenses		306			235			970			693
Service costs included in other nonelectric expenses		11			8			33			23
Nonservice costs capitalized as regulatory assets		150			284			396			905
Nonservice costs included in n onservice cost components of postretirement benefits		328			889			1,037			2,614

1 2 . Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

Cash Equivalents —The carrying amount approximates fair value because of the short-term maturity of those instruments.

Short-Term Debt —The carrying amount approximates fair value because the debt obligations are short-term and the balances outstanding as of September 30, 2020 and December 31, 2019 related to the Otter Tail Corporation Credit Agreement were subject to variable interest rates of LIBOR plus 1.50 %, which approximate market rates.

Long-Term Debt including Current Maturities —The fair value of the Company's and OTP’s long-term debt is estimated based on the current market indications of rates available to the Company for the issuance of debt. The fair value measurements of the Company’s long-term debt issues fall into level 2 of the fair value hierarchy set forth in ASC 820.

	September 30, 2020						December 31, 2019
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	44,904		$	44,904		$	21,199		$	21,199
Short-Term Debt		( 48,600	)		( 48,600	)		( 6,000	)		( 6,000	)
Long-Term Debt including Current Maturities		( 764,489	)		( 867,972	)		( 689,764	)		( 742,279	)

13. Property, Plant and Equipment

No update required for interim reporting period.

Table of Contents

1 4 . Income Tax Expense

The following table provides a reconciliation of income tax expense calculated at the net composite federal and state statutory rate on income before income taxes and income tax expense reported on the Company’s consolidated statements of income for the three - and nine -month periods ended September 30, 2020 and 2019:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2020			2019			2020			2019
Income Before Income Taxes	$	45,031		$	29,681		$	95,726		$	80,402
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%)	$	11,708		$	7,717		$	24,889		$	20,905
(Decreases) Increases in Tax from:
Differences Reversing in Excess of Federal Rates		( 1,678	)		( 933	)		( 3,450	)		( 2,690	)
Allowance for Funds Used During Construction – Equity		( 388	)		( 239	)		( 948	)		( 419	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		( 259	)		( 258	)		( 775	)		( 774	)
Research and Development and Other Tax Credits		( 263	)		( 612	)		( 649	)		( 987	)
Excess Tax Deduction – Equity Method Stock Awards		-			-			( 535	)		( 827	)
Corporate Owned Life Insurance		( 155	)		( 50	)		( 141	)		( 609	)
Reconciliation and Prior Period Adjustments		172			( 688	)		172			( 722	)
Other Items – Net		( 40	)		( 1	)		( 20	)		30
Income Tax Expense	$	9,097		$	4,936		$	18,543		$	13,907
Effective Income Tax Rate		20.2	%		16.6	%		19.4	%		17.3	%

The following table summarizes the activity related to the Company’s unrecognized tax benefits:

(in thousands)	2020			2019
Balance on January 1	$	1,488		$	1,282
(Decreases) Increases Related to Tax Positions for Prior Years		( 27	)		37
Increases Related to Tax Positions for Current Year		123			153
Uncertain Positions Resolved During Year		( 586	)		-
Decrease from the Expiration of Statute of Limitations		( 139	)		( 170	)
Balance on September 30	$	859		$	1,302

The balance of unrecognized tax benefits as of September 30, 2020 would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of September 30, 2020 could be reduced by as much as $ 139,000 within the next 12 months due to expected settlement. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes in its consolidated statement of income.

The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of November 1, 2020, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2017 for federal and North Dakota income taxes and prior to 2016 for Minnesota income taxes.

Table of Contents

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

COVID-19

Otter Tail Corporation (the Company, we, us and our) continues to monitor the progression of the coronavirus disease 2019 (COVID-19) and its impact on our businesses, employees, customers, construction contractors and vendors. As this pandemic continues, we are following the directives and advice of government leaders and medical professionals and have adopted practices to help curtail the spread of the virus and mitigate its impact on our communities, employees, construction contractors, customers and business operations. Our Electric segment business provides a critical service to our customers and our manufacturing platform businesses provide products and support to critical infrastructure industries. All of our operating companies have been deemed critical infrastructure businesses. Accordingly, we continue to operate our businesses in a manner that is safe for our employees and our customers.

COVID-19 and the resulting economic conditions have had a material negative impact on the results of operations in our Manufacturing segment, and, to a lesser extent, also impacted the results of operations of our Electric and Plastics segments, but have not had a material impact on our consolidated financial position or liquidity. We saw a reduction in customer demand in our Manufacturing segment in late March 2020 and experienced significantly lower levels of customer demand in our Manufacturing segment through the end of June 2020 but began to see some recovery in demand in the third quarter of 2020. A moderate level of reduced demand may continue in our Manufacturing segment over the near term. Within our Electric segment, we have experienced reduced demand from commercial and industrial customers. In our Plastics segment, we experienced lower sales in the second quarter as distributors reduced inventory levels due to uncertainty over the impact of COVID-19, but experienced a recovery in sales and increased margins in the third quarter due to higher PVC pipe prices relative to lower-cost inventory.

Beginning in April 2020, in response to the actual and anticipated impact of COVID-19 on our business operations, we implemented a variety of policies, including furloughs, shift and pay reductions, wage and hiring freezes, suspension of certain employee benefits, a workforce reduction and other cost reduction efforts to mitigate the negative impact to our financial results. We continue to monitor the impacts of the pandemic on our businesses and will adjust our response as circumstances evolve .

Financial And OTHER metrics USED IN THE FOLLOWING DISCUSSION

Heating Degree Days (HDDs) is a measure of how much (in degrees), and for how long (in days), the outside air temperature was below a certain normalized level. This measure is commonly used in calculations relating to the energy consumption required to heat buildings.

Cooling Degree Days (CDDs) is a measure of how much (in degrees), and for how long (in days), the outside air temperature was above a certain normalized level. This measure is commonly used in calculations relating to the energy consumption required to cool buildings.

Otter Tail Power Company (OTP) generally bases its forecasted kilowatt-hour (kwh) sales and rates on expected consumption under a normal level of HDDs and CDDs over a given period of time in its service territory. Increased or decreased levels of consumption for certain customer classifications are attributed to deviation from the norms and are a significant factor influencing consumption of electricity across our service territory. We present HDDs and CDDs to provide an indication of the impact of weather on kwh sales, revenues and earnings relative to forecast and on period-to-period results.

Backlog , expressed in dollars, is the level of sales orders received but not yet completed by a company or operating segment. The Company discloses these figures for its Manufacturing segment as an indication of future business volume within the segment.

Utility Rate Base is the value of property on which a public utility is permitted to earn a specified rate of return in accordance with rules set by a regulatory agency. In general, the rate base consists of the value of property used by the utility in providing service. Rate base can include: cash, working capital, materials and supplies, deductions for accumulated provisions for depreciation, contributions in aid of construction, customer advances for construction, accumulated deferred income taxes, and accumulated deferred investment tax credits, dependent on the method that is used in the calculation, which can vary from jurisdiction to jurisdiction. The Company presents actual and forecasted levels of utility rate base in its outlook to provide an indication of expected investments on which the Company expects to earn future returns.

Table of Contents

Results of Operations

Following is an analysis of the Company’s operating results by business segment for the three and nine months ended September 30, 2020 and 2019 followed by a discussion of changes in our consolidated financial position during the nine months ended September 30, 2020 and our business outlook for the remainder of 2020.

Comparison of the Three Months Ended September 30, 2020 and 2019

Consolidated operating revenues were $235.8 million for the three months ended September 30, 2020 compared with $228.7 million for the three months ended September 30, 2019. Operating income was $52.7 million for the three months ended September 30, 2020 compared with $37.3 million for the three months ended September 30, 2019. The Company recorded diluted earnings per share of $0.87 for the three months ended September 30, 2020 compared with $0.62 for the three months ended September 30, 2019.

Amounts presented in the segment tables that follow for operating revenues, cost of products sold and other nonelectric operating expenses for the three-month periods ended September 30, 2020 and 2019 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:

Intersegment Eliminations (in thousands)	September 30, 2020		September 30, 2019
Operating Revenues:
Electric	$	10	$	9
Nonelectric		--		--
Costs of Products Sold		3		5
Other Nonelectric Expenses		7		4

Electric

	Three Months Ended
	September 30,								%
(in thousands)	2020		2019			Change			Change
Retail Sales Revenues from Contracts with Customers	$	96,827	$	100,345		$	(3,518	)		(3.5	)
Changes in Accrued Revenues under Alternative Revenue Programs		2,778		(921	)		3,699			401.6
Total Retail Sales Revenue	$	99,605	$	99,424		$	181			0.2
Transmission Services Revenue		12,288		11,692			596			5.1
Wholesale Revenues – Company Generation		1,500		1,631			(131	)		(8.0	)
Other Revenues		1,830		1,626			204			12.5
Total Operating Revenues	$	115,223	$	114,373		$	850			0.7
Production Fuel		11,554		18,331			(6,777	)		(37.0	)
Purchased Power – System Use		13,428		13,163			265			2.0
Electric Operation and Maintenance Expenses		32,845		35,869			(3,024	)		(8.4	)
Depreciation and Amortization		15,647		15,198			449			3.0
Property Taxes		4,333		3,965			368			9.3
Operating Income	$	37,416	$	27,847			9,569			34.4
Electric Megawatt-hour (mwh) Sales
Retail mwh Sales		1,075,336		1,091,427			(16,091	)		(1.5	)
Wholesale mwh Sales – Company Generation		75,884		71,506			4,378			6.1
HDDs		61		42			19			45.2
CDDs		363		288			75			26.0

The following table shows heating and cooling degree days as a percent of normal:

	Three Months ended September 30,
	2020			2019
HDDs		115.1	%		76.4	%
CDDs		104.6	%		83.0	%

Table of Contents

The following table summarizes the estimated effect on diluted earnings per share of the difference in retail kwh sales under actual weather conditions and expected retail kwh sales under normal weather conditions in the third quarters of 2020 and 2019 and between quarters:

		2020 vs Normal				2019 vs Normal				2020 vs 2019
Effect on Diluted Earnings Per Share		$	0.01			$	(0.02	)		$	0.03

The $0.2 million increase in retail sales revenue includes:

●

A $3.3 million increase in Minnesota and North Dakota Renewable Resource Adjustment (RRA) Rider revenues related to earning a return on funds invested in the Merricourt Wind Energy Center (Merricourt) while the project is under construction.

●

A $2.1 million increase in Transmission Cost Recovery (TCR) revenues, mainly due to the recognition of Minnesota TCR Rider revenues resulting from a favorable decision regarding the state jurisdictional treatment of federally approved transmission rate incentives.

●

A $1.5 million increase in retail revenues mainly related to increased residential kwh consumption due to favorable weather impacts in the third quarter of 2020 compared to the third quarter of 2019.

●

A $1.1 million increase in revenues from the North Dakota Generation Cost Recovery (GCR) Rider which went into effect in July 2019 to provide a return on funds invested in Astoria Station while the generation project is under construction.

These increases in revenue were mostly offset by:

●

A $6.6 million decrease in retail revenue related to the recovery of decreased fuel and purchased power costs to serve retail customers. Fuel costs decreased as a result of a 24.0% decrease in kwhs generated at OTP's fuel-burning power plants, but also as a result of a 37.9% decrease in the cost of fuel per kwh generated at Coyote Station related to higher-cost coal burned in the third quarter of 2019 due to the absorption of mine operating costs in inventory during Coyote Station's second quarter 2019 maintenance shutdown.

●

A $1.2 million decrease in revenue due to decreased kwh sales to commercial and industrial customers, mainly due to COVID-19-related impacts in the third quarter of 2020.

Transmission services revenue increased $0.6 million mainly due to an increase in facility service agreement revenues related to transmission upgrades made to accommodate independent generator access to the transmission grid.

Production fuel costs decreased $6.8 million due to a 24.0% decrease in kwhs generated from our fuel-burning plants and a 21.7% decrease in fuel cost per kwh of generation, weighted heavily by higher fuel costs per kwh of generation at Coyote Station in the third quarter of 2019. Coyote Station was down for maintenance in the second quarter of 2019 and mine operating costs incurred during the second quarter and absorbed in inventory were expensed as fuel costs when Coyote Station resumed operations in the third quarter of 2019.

The cost of purchased power to serve retail customers increased $0.3 million as a result of an 18.7% increase in kwh purchases, mostly offset by a 14.1% decrease in the cost per kwh purchased. The increase in purchased power volume was a function of reduced generation at Big Stone Plant, which went offline for scheduled maintenance in September 2020, and the availability of low-priced energy in the wholesale market. The decrease in purchased power prices was driven mainly by low prices for natural gas-fired generation.

Electric operating and maintenance expense decreased $3.0 million, including:

●

A $1.0 million decrease in labor and benefit costs due to an increase in capitalized labor related to an increase in construction activity and decreases in corporate overhead and performance incentive costs.

●

A $0.9 million decrease in transmission tariff expenses related to decreased rates.

●

A $0.6 million decrease in Hoot Lake Plant external services costs related to Unit 2 turbine maintenance repairs completed in the third quarter of 2019.

●

A $0.5 million decrease in tree-trimming and vegetation maintenance expenses.

●

A $0.5 million decrease in travel-related expenses related to Covid-19 travel restrictions.

These decreases in expense were partially offset by:

●

A $0.4 million increase in customer bad debt expense provisions, mainly due to adoption of Covid-19-related service suspension and debt collection policies.

Property tax expense increased $0.4 million due to property additions and increased jurisdictional valuations.

Table of Contents

Depreciation expense increased $0.4 million mainly due to 2019 capital additions for generation and transmission plant.

Manufacturing

	Three Months Ended
	September 30,							%
(in thousands)	2020		2019		Change			Change
Operating Revenues	$	59,849	$	65,722	$	(5,873	)		(8.9	)
Cost of Products Sold		44,444		51,399		(6,955	)		(13.5	)
Operating Expenses		6,901		6,846		55			0.8
Depreciation and Amortization		3,759		3,505		254			7.2
Operating Income	$	4,745	$	3,972	$	773			19.5

The $5.9 million decrease in revenues in our Manufacturing segment includes the following:

●

Revenues at BTD Manufacturing, Inc. (BTD) decreased $5.4 million between quarters, driven by a $4.1 million decline in prices of materials passed through to customers and $1.3 million in decreased sales volumes. The decrease in sales volumes primarily resulted from lower parts sales to construction and industrial equipment manufacturers, partially offset by increased parts sales to recreational vehicle, agricultural and lawn and garden equipment manufacturers. Increases in parts revenue related to favorable product pricing were offset by lower tooling and scrap revenues.

●

Revenues at T.O. Plastics, Inc. (T.O. Plastics), our manufacturer of thermoformed plastic and horticultural products, decreased $0.5 million, mainly due to market softness generated by the uncertainty of how COVID-19 was going to impact these end markets.

The $7.0 million decrease in cost of products sold in our Manufacturing segment includes the following:

●

Cost of products sold at BTD decreased $6.6 million, mainly as a result of the $4.1 million in lower material costs passed through to customers but also due to improved productivity and the decrease in sales volume.

●

Cost of products sold at T.O. Plastics decreased $0.3 million related to the decrease in sales volume.

Plastics

	Three Months Ended
	September 30,						%
(in thousands)	2020		2019		Change		Change
Operating Revenues	$	60,693	$	48,566	$	12,127		25.0
Cost of Products Sold		42,415		37,353		5,062		13.6
Operating Expenses		3,250		2,872		378		13.2
Depreciation and Amortization		905		865		40		4.6
Operating Income	$	14,123	$	7,476	$	6,647		88.9

Plastics segment revenues and operating income increased $12.1 million and $6.6 million, respectively, primarily due to a 21.2% increase in pounds of polyvinyl chloride (PVC) pipe sold driven by distributors rebuilding inventory in the third quarter of 2020 after reducing inventory levels in the second quarter of 2020 due to uncertainty over the impact of COVID-19 on sales. Cost of products sold increased $5.1 million due to the increase in sales volume, partially offset by a 6.3% decrease in the cost per pound of PVC pipe sold. The decrease in the cost per pound of PVC pipe sold is primarily due to lower material input costs. The $0.4 million increase in segment operating expenses is mainly due to increased employee benefit costs.

Table of Contents

Corporate

Corporate includes items such as corporate staff and overhead costs, the results of our captive insurance company and other items excluded from the measurement of operating segment performance. Corporate is not an operating segment. Rather it is added to operating segment totals to reconcile to totals on our consolidated statements of income.

	Three Months Ended
	September 30,							%
(in thousands)	2020		2019		Change			Change
Operating Expenses	$	3,471	$	1,951	$	1,520			77.9
Depreciation and Amortization		84		89		(5	)		(5.6	)

The $1.5 million increase in corporate operating expenses is mainly due to an increase in performance incentive accruals driven by improved quarter-over-quarter results.

Interest Charges

Interest charges increased to $8.6 million in the three months ended September 30, 2020 from $7.5 million in the three months ended September 30, 2019. The $1.1 million increase in interest charges is primarily due to an increase in interest expense at OTP related to debt issuances of $100 million in October of 2019, $35 million in February of 2020 and $40 million in August 2020 under OTP’s 2019 Note Purchase Agreement.

Other Income

Other income increased to $1.7 million in the three months ended September 30, 2020 from $1.0 million in the three months ended September 30, 2019. The $0.7 million increase in other income includes:

●

A $0.3 million increase in allowance for equity funds used during construction at OTP mostly related to the Minnesota share of construction work in progress on OTP’s Astoria Station project.

●

A $0.2 million increase in the cash surrender value of corporate-owned life insurance policies held by the Company.

●

A $0.1 million decrease in unrealized losses on equity investments held by our captive insurance company, Otter Tail Assurance Limited, in the third quarter of 2020.

Income Tax Expense

Income tax expense increased $4.2 million in the three months ended September 30, 2020 compared with the three months ended September 30, 2019, mainly due to the tax effect of a $15.3 million increase in income before income taxes. The following table provides a reconciliation of income tax expense calculated at our net composite federal and state statutory rate on income before income taxes on our consolidated statements of income.

	Three Months Ended September 30,
(in thousands)	2020			2019
Income Before Income Taxes	$	45,031		$	29,681
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%)	$	11,708		$	7,717
(Decreases) Increases in Tax from:
Differences Reversing in Excess of Federal Rates		(1,678	)		(933	)
Allowance for Funds Used During Construction – Equity		(388	)		(239	)
Research and Development and Other Tax Credits		(263	)		(612	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(259	)		(258	)
Corporate Owned Life Insurance		(155	)		(50	)
Reconciliation and Prior Period Adjustments		172			(688	)
Other Items – Net		(40	)		(1	)
Income Tax Expense	$	9,097		$	4,936
Effective Income Tax Rate		20.2	%		16.6	%

Table of Contents

Comparison of the Nine Months Ended September 30, 2020 and 2019

Consolidated operating revenues were $663.3 million for the nine months ended September 30, 2020 compared with $703.8 million for the nine months ended September 30, 2019. Operating income was $119.9 million for the nine months ended September 30, 2020 compared with $103.6 million for the nine months ended September 30, 2019. The Company recorded diluted earnings per share of $1.89 for the nine months ended September 30, 2020 compared with $1.67 for the nine months ended September 30, 2019.

Amounts presented in the segment tables that follow for operating revenues, cost of products sold and other nonelectric operating expenses for the nine-month periods ended September 30, 2020 and 2019 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:

Intersegment Eliminations (in thousands)	September 30, 2020		September 30, 2019
Operating Revenues:
Electric	$	39	$	36
Nonelectric		--		3
Costs of Products Sold		10		25
Other Nonelectric Expenses		29		14

Electric

	Nine Months Ended
	September 30,								%
(in thousands)	2020		2019			Change			Change
Retail Sales Revenues from Contracts with Customers	$	288,861	$	303,276		$	(14,415	)		(4.8	)
Changes in Accrued Revenues under Alternative Revenue Programs		2,900		(1,601	)		4,501			281.1
Total Retail Sales Revenue	$	291,761	$	301,675		$	(9,914	)		(3.3	)
Transmission Services Revenue		32,802		34,023			(1,221	)		(3.6	)
Wholesale Revenues – Company Generation		3,141		4,099			(958	)		(23.4	)
Other Revenues		5,548		4,929			619			12.6
Total Operating Revenues	$	333,252	$	344,726		$	(11,474	)		(3.3	)
Production Fuel		34,077		45,547			(11,470	)		(25.2	)
Purchased Power – System Use		45,940		54,748			(8,808	)		(16.1	)
Other Operation and Maintenance Expenses		106,639		114,107			(7,468	)		(6.5	)
Depreciation and Amortization		47,063		44,765			2,298			5.1
Property Taxes		12,601		11,824			777			6.6
Operating Income	$	86,932	$	73,735		$	13,197			17.9
Electric mwh Sales
Retail mwh Sales		3,538,299		3,657,618			(119,319	)		(3.3	)
Wholesale mwh Sales – Company Generation		156,948		153,645			3,303			2.1
HDDs		3,968		4,692			(724	)		(15.4	)
CDDs		533		392			141			36.0

The following table shows heating and cooling degree days as a percent of normal:

	Nine Months ended September 30,
	2020			2019
HDDs		99.3	%		118.0	%
CDDs		116.9	%		86.0	%

The following table summarizes the estimated effect on diluted earnings per share of the difference in retail kwh sales under actual weather conditions and expected retail kwh sales under normal weather conditions in the first nine months of 2020 and 2019 and between the periods:

		2020 vs Normal				2019 vs Normal				2020 vs 2019
Effect on Diluted Earnings Per Share		$	0.02			$	0.06			$	(0.04	)

Table of Contents

The $9.9 million decrease in retail sales revenue includes:

●

An $18.6 million decrease in retail revenue related to the recovery of decreased fuel and purchased power costs to serve retail customers. Decreased demand caused by the milder winter weather contributed to a 21.2% decrease in kwhs generated for system use and a $10.9 million decrease in fuel costs. Also, the cost of fuel burned per kwh of generation was higher in the first nine months of 2019 as a result of the absorption of fixed coal extraction costs in inventory during Coyote Station's second quarter 2019 maintenance shutdown. Purchased power costs decreased by $8.8 million, despite an 8.8% increase in kwhs purchased, due to a 22.8% decrease in purchased power prices resulting from a decrease in market demand between periods.

●

A $2.4 million decrease in revenues related to decreased consumption due to milder winter weather in 2020 compared with 2019, reflected in the 15.4% decrease in HDDs in the nine months ended September 30, 2020 compared with the nine months ended September 30, 2019. The decrease in consumption due to the decrease in HDDS was only partially offset by an increase in consumption related to warmer summer weather in 2020 compared with 2019.

●

A $1.6 million decrease in revenue due to decreased kwh sales to commercial and industrial customers mainly due to COVID-19 related impacts in the second and third quarters of 2020.

●

A $1.0 million decrease in retail revenue in South Dakota related to the first quarter 2019 reversal of a tax refund provision accrued in 2018 in connection with OTP's 2018 South Dakota rate case settlement agreement.

These decreases in revenue were partially offset by:

●

An $8.5 million increase in Minnesota and North Dakota RRA Rider revenues related to earning a return on funds invested in Merricourt while the project is under construction.

●

A $2.4 million increase in revenues from the North Dakota Generation Rider which went into effect in July 2019 to provide a return on funds invested in Astoria Station while the generation project is under construction.

●

A $2.1 million increase in Minnesota TCR Rider revenues, mainly due to the recognition of revenues resulting from a favorable decision regarding state jurisdictional treatment of federally approved transmission rate incentives.

●

A $0.6 million increase in conservation improvement program (CIP) cost recovery and incentive revenues mainly related to the recovery of increased program spending in Minnesota and South Dakota.

Transmission services revenue decreased $1.2 million mainly due to a $2.1 million reduction in transmission tariff revenues related to decreased transmission volume resulting from lower electrical demand partly attributable to the impact of COVID-19, partially offset by a $0.8 million increase in facility service agreement revenues related to transmission upgrades made to accommodate independent generator access to the transmission grid.

Wholesale electric revenues decreased $1.0 million, despite a 2.1% increase in wholesale kwh sales, due to a 25% decrease in revenue per kwh sold. The lower wholesale prices per kwh resulted in a $0.4 million decrease in margins on wholesale energy sales from OTP’s generating units in the first nine months of 2020 compared with the first nine months of 2019.

Production fuel costs decreased $11.5 million due to a 23.5% decrease in kwhs generated at OTP’s fuel-burning generation plants and a 2.2% decrease in fuel costs per kwh generated. Decreases in generation of 41.5% at Big Stone Plant and 46.1% at Hoot Lake Plant, which were curtailed due to economic dispatch as reduced demand and lower prices for alternative fuels and generation sources drove market prices for electricity down in in the first nine months of 2020, were only partially offset by a 25.7% increase in generation at Coyote Station, which was offline for maintenance during the entire second quarter of 2019.

The cost of purchased power to serve retail customers decreased $8.8 million as a result of a 22.8% decrease in purchased power prices, partially offset by an 8.8% increase in kwhs purchased. The increase in kwhs purchased was mainly due to the decrease in market prices for electricity driven by low prices for natural gas-fired generation in combination with lower demand in the second quarter of 2020 due to COVID-19-related declines in electricity use by commercial and industrial consumers.

Electric operating and maintenance expense decreased $7.5 million, including:

●

A $3.5 million decrease in contracted services and materials and supplies expenses at Coyote Station, mainly related to the plant's second quarter 2019 extended maintenance outage.

●

A $2.4 million decrease in transmission tariff expenses related to decreased rates.

●

A $1.1 million decrease in materials and supplies and contracted services expenses at Hoot Lake Plant related to second quarter 2019 turbine repairs.

●

A $0.9 million decrease in travel-related expenses due to COVID-19 travel restrictions.

●

A $0.7 million decrease in tree-trimming and vegetation maintenance expenses.

Table of Contents

●

A $0.6 million decrease in pollution control reagent costs due to a 24.0% decrease in kwhs generated at OTP's coal burning plants.

These items were partially offset by:

●

A $1.1 million increase in customer bad debt expense provisions, mainly due to adoption of COVID-19-related service suspension and debt collection policies.

●

A $0.5 million in CIP expenditures.

Depreciation expense increased $2.3 million mainly due to 2019 capital additions for generation and transmission plant, the new customer information system that went into service during the first quarter of 2019 and new service vehicles.

Property tax expense increased $0.8 million due to property additions and increased jurisdictional valuations.

Manufacturing

	Nine Months Ended
	September 30,							%
(in thousands)	2020		2019		Change			Change
Operating Revenues	$	174,276	$	217,040	$	(42,764	)		(19.7	)
Cost of Products Sold		131,145		167,002		(35,857	)		(21.5	)
Operating Expenses		19,678		22,880		(3,202	)		(14.0	)
Depreciation and Amortization		11,244		10,606		638			6.0
Operating Income	$	12,209	$	16,552	$	(4,343	)		(26.2	)

The $42.8 million decrease in revenues in our Manufacturing segment includes the following:

●

Revenues at BTD decreased $41.6 million. Parts revenue was down $41.4 million, mainly due to decreased sales volumes to all end market customer categories served by BTD, in order of magnitude: construction, lawn and garden, industrial and energy equipment, recreational vehicle and agricultural end markets. The decreased sales mainly resulted from customers implementing temporary plant shutdowns due to the COVID-19 pandemic. Lower prices related to the pass through of lower material costs accounted for a $17.1 million decrease in parts revenue, partially offset by $1.2 million in price increases exclusive of the pass through of material cost reductions.

●

Revenues at T.O. Plastics decreased $1.2 million primarily as a result of lower product demand from customers due to COVID-19-related impacts on customer’s sales and service activities.

The $35.9 million decrease in cost of products sold in our Manufacturing segment includes the following:

●

Cost of products sold at BTD decreased $35.7 million as a result of both the decreased sales volume and the $17.1 million in lower material costs passed through to customers.

●

Cost of products sold at T.O. Plastics decreased $0.2 million due to a $1.4 million decrease in material costs related to the decrease in sales volume, mostly offset by increases in other indirect costs and an increase in rental costs for more warehouse space.

The $3.2 million decrease in operating expenses in our Manufacturing segment includes a $2.3 million decrease in operating expenses at BTD related to initiatives taken at BTD to mitigate the negative impacts on sales related to COVID-19, mainly reductions in travel and outside services expenditures. Operating expenses at T.O. Plastics decreased $0.9 million, including $0.4 million as a result of the receipt of insurance settlement proceeds in the first quarter of 2020 and a $0.3 million write off of the value of destroyed property in 2019 related to the March 2019 partial roof collapse. T.O, Plastics travel and other selling expenses decreased by $0.2 million due to restrictions on activity in response to COVID-19-related safety initiatives.

BTD incurred $1.0 million in termination costs in the second quarter of 2020, with $0.9 million charged to cost of products sold and $0.1 million charged to operating expense, related to headcount reductions across all its sites in response to the ongoing reduction in sales volume.

We estimate COVID-19 issues at BTD negatively impacted our earnings by approximately $0.08 per share in the first nine months of 2020. This relates to reduced sales as customers initiated or continued temporary plant shutdowns which caused lost labor productivity, and costs related to personal protective equipment. BTD also continued to pay health care costs for furloughed employees.

Table of Contents

Plastics

	Nine Months Ended
	September 30,						%
(in thousands)	2020		2019		Change		Change
Operating Revenues	$	155,769	$	142,100	$	13,669		9.6
Cost of Products Sold		115,432		110,348		5,084		4.6
Operating Expenses		8,990		8,486		504		5.9
Depreciation and Amortization		2,667		2,617		50		1.9
Operating Income	$	28,680	$	20,649	$	8,031		38.9

Plastics segment revenues and operating income increased $13.7 million and $8.0 million, respectively, due to a 10.2% increase in pounds of PVC pipe sold in combination with a decrease in cost per pound of pipe sold. The sales volume increase resulted from a combination of factors including improved market conditions during the third quarter of 2020 due to limited effects of COVID-19 and concerns over raw material supply and product availability due to two resin suppliers invoking force majeure, anticipated impacts from hurricanes, significant global demand for PVC resin and limited pipe inventory across the country. Cost of products sold increased $5.1 million due to the increase in sales volume, partially offset by a 5.0% decrease in the cost per pound of PVC pipe sold primarily due to lower material input costs. The $0.5 million increase in segment operating expenses is due to increases in salary and benefit expenses, contracted service costs and corporate management fees.

Corporate

	Nine Months Ended
	September 30,						%
(in thousands)	2020		2019		Change		Change
Operating Expenses	$	7,638	$	7,052	$	586		8.3
Depreciation and Amortization		256		241		15		6.2

Corporate operating expenses increased $0.6 million mainly as a result of a $0.4 million decrease in corporate costs charged to subsidiaries, a $0.4 million increase in labor costs and a $0.2 million increase in insurance costs, partially offset by a $0.3 million decrease in contracted service expenditures.

Interest Charges

Interest charges increased to $25.4 million in the nine months ended September 30, 2020 from $23.2 million in the nine months ended September 30, 2019. The $2.2 million increase in interest charges is primarily due to an increase in interest expense at OTP related to debt issuances of $100 million in October of 2019, $35 million in February of 2020 and $40 million in August 2020 under OTP’s 2019 Note Purchase Agreement.

Other Income

Other income increased to $3.7 million in the nine months ended September 30, 2020 from $3.1 million in the nine months ended September 30, 2019. The $0.6 million increase in other income includes a $1.5 million increase in allowance for equity funds used during construction (AFUDC) at OTP, mostly related to the Minnesota share of construction work in progress on OTP’s Astoria Station project, partially offset by a $0.8 million decrease in the cash surrender value of corporate-owned life insurance policies held by the Company.

Table of Contents

Income Tax Expense

Income tax expense increased $4.6 million in the nine months ended September 30, 2020 compared with the nine months ended September 30, 2019, mainly due to the tax effect of a $15.3 million increase in income before income taxes. The following table provides a reconciliation of income tax expense calculated at our net composite federal and state statutory rate on income before income taxes on our consolidated statements of income.

	Nine Months Ended September 30,
(in thousands)	2020			2019
Income Before Income Taxes	$	95,726		$	80,402
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%)	$	24,889		$	20,905
(Decreases) Increases in Tax from:
Differences Reversing in Excess of Federal Rates		(3,450	)		(2,690	)
Allowance for Funds Used During Construction – Equity		(948	)		(419	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(775	)		(774	)
Research and Development Tax Credits		(649	)		(987	)
Excess Tax Deduction – Equity Method Stock Awards		(535	)		(827	)
Corporate Owned Life Insurance		(141	)		(609	)
Reconciliation and Prior Period Adjustments		172			(722	)
Other Items – Net		(20	)		30
Income Tax Expense	$	18,543		$	13,907
Effective Income Tax Rate		19.4	%		17.3	%

Liquidity

We believe our financial condition is strong and our cash, other liquid assets, operating cash flows, existing lines of credit, access to capital markets, and borrowing ability because of investment-grade credit ratings, when taken together, provide us ample liquidity to conduct business operations and fund capital expenditures related to expansion of existing businesses and development of new projects. Our liquidity, including our operating cash flows and access to capital markets, can be impacted by macroeconomic factors outside of our control, such as those which may be caused by COVID-19. In addition, our liquidity could be impacted by non-compliance with covenants under our various debt instruments. As of September 30, 2020, we were in compliance with all debt covenants (see the Financial Covenant section under Capital Resources below).

As of September 30, 2020, COVID-19 and the resulting deteriorating economic conditions had not had a material impact on our liquidity. We continue to have sufficient liquidity under our credit facilities to support our operating companies based on the current economic environment. We are closely monitoring our liquidity and capital market conditions given the uncertainty surrounding the impact of COVID-19, which could have an adverse effect on the availability and terms of future debt and equity financing.

The following table presents the status of our lines of credit as of September 30, 2020 and December 31, 2019:

(in thousands)	Line Limit		In Use on September 30, 2020		Restricted due to Outstanding Letters of Credit		Available on September 30, 2020		Available on December 31, 2019
Otter Tail Corporation Credit Agreement	$	170,000	$	48,600	$	--	$	121,400	$	164,000
OTP Credit Agreement		170,000		--		7,670		162,330		154,524
Total	$	340,000	$	48,600	$	7,670	$	283,730	$	318,524

We have adopted an internal risk tolerance metric to maintain a minimum of $50 million of liquidity under the Otter Tail Corporation Credit Agreement. Should additional liquidity be needed, this agreement includes an accordion feature allowing us to increase the amount available to $290 million, subject to certain terms and conditions. The OTP Credit Agreement also includes an accordion feature allowing OTP to increase that facility to $250 million, subject to certain terms and conditions.

Our At-the-Market equity offering program, which allows us to sell common shares up to an aggregate sales price of $75 million, remains in effect. We issued $35.0 million of common equity under our At-the-Market offering program, Dividend Reinvestment and Employee Stock Purchase plans in the first nine months of 2020. We expect to issue up to an additional $20 million in common equity under these programs into 2021 depending on conditions in the equity capital markets caused by the COVID-19 pandemic or other factors.

Table of Contents

Equity and debt financing will be required in the period 2020 through 2024 given the expansion plans related to our Electric segment to fund construction of new rate base investments. Also, such financing will be required should we decide to reduce borrowings under our lines of credit or refund or retire early any of our presently outstanding debt, to complete acquisitions or for other corporate purposes. The terms and conditions and the timing of our equity and debt financing activities could be impacted by the economic effects of COVID-19 and the resulting market volatility. In addition, our borrowing costs can be impacted by changing interest rates on short-term and long-term debt and ratings assigned to us by independent rating agencies, which in part are based on certain credit measures such as interest coverage and leverage ratios.

The determination of the amount of future cash dividends to be declared and paid will depend on, among other things, our financial condition, improvement in earnings per share, cash flows from operations, the level of our capital expenditures and our future business prospects. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by our subsidiaries. See note 7 to consolidated financial statements for additional information. The decision to declare a dividend is reviewed quarterly by the board of directors. On February 4, 2020 our board of directors increased the quarterly dividend from $0.35 to $0.37 per common share.

2020 Cash Flows Compared with 2019 Cash Flows

Cash provided by operating activities was $141.3 million for the nine months ended September 30, 2020 compared with cash provided by operating activities of $105.1 million for the nine months ended September 30, 2019. The primary reasons for the $36.2 million increase in cash provided by operations between the periods were an $11.3 million decrease in discretionary pension fund contributions, a $10.7 million increase in net income, a $7.0 million reduction in cash used for working capital items and a $3.0 million increase in the non-cash depreciation expense between the periods. The reduction in cash used for working capital items was mainly due to an $8.1 million decrease in cash used for trade accounts payable at BTD mostly related to lower material purchases resulting from a reduction in business activity in 2020 related to COVID-19.

Net cash used in investing activities was $222.4 million for the nine months ended September 30, 2020 compared with $151.1 million for the nine months ended September 30, 2019. The $71.3 million increase is mainly due to a $77.1 million increase in cash used for construction expenditures at OTP, partially offset by a $6.2 million net decrease in capital expenditures in our nonutility businesses. OTP’s cash used for capital expenditures totaled $210.0 million in the first nine months of 2020 compared with $132.9 million in the first nine months of 2019. The majority of the 2020 expenditures at OTP related to the construction of Astoria Station and Merricourt.

Net cash provided by financing activities was $104.8 million for the nine months ended September 30, 2020 compared with net cash provided by financing activities of $46.0 million for the nine months ended September 30, 2019. Financing activities in the first nine months of 2020 included $75.0 million in proceeds from the issuance of long-term debt at OTP under its 2019 Note Purchase Agreement to fund its current construction program expenditures. Further information on the debt issuance is provided below under “Capital Resources.” We also borrowed $42.6 million under the Otter Tail Corporation Credit Agreement and raised net proceeds of $32.7 million from the issuance of common stock. The proceeds from the line borrowings and stock issuances provided the majority of funds for $105 million in equity contributions to OTP to fund its construction program expenditures. Financing activities in the first nine months of 2020 also included $45.1 million in common dividend payments.

Financing activities in the first nine months of 2019 included proceeds of $90.4 million from borrowings under the OTP and Otter Tail Corporation credit agreements which were used, together with cash flows from operations, to fund OTPs capital expenditures. The Company also paid $41.8 million in common dividends in the first nine months of 2019.

Table of Contents

CAPITAL REQUIREMENTS

201 9 -20 2 4 Capital Expenditures

In June 2020, we updated our 2020-2024 anticipated capital expenditures, shifting the timing of expenditures between years and projects as a result of more definitive plans with no material impact on the $1.0 billion five-year expenditure total. The following table shows our 2019 capital expenditures and June 30, 2020 revised 2020 through 2024 anticipated capital expenditures and electric utility average rate base:

(in millions)	2019		2020			2021			2022			2023			2024			Total
Capital Expenditures:
Electric Segment:
Renewables and Natural Gas Generation			$	258		$	65		$	53		$	--		$	--		$	376
Technology and Infrastructure				--			11			28			32			28			99
Distribution Plant Replacements				20			25			28			31			30			134
Transmission (includes replacements)				62			14			30			30			30			166
Other				26			23			25			25			24			123
Total Electric Segment	$	187	$	366		$	138		$	164		$	118		$	112		$	898
Manufacturing and Plastics Segments		20		14			17			17			19			17			84
Total Capital Expenditures	$	207	$	380		$	155		$	181		$	137		$	129		$	982
Total Electric Utility Average Rate Base	$	1,170	$	1,415		$	1,587		$	1,664		$	1,726		$	1,765
Rate Base Growth				20.9	%		12.2	%		4.9	%		3.7	%		2.3	%

Execution on the anticipated electric utility capital expenditure plan is expected to grow rate base 8.6% and be a key driver in increasing utility earnings over the 2020 through 2024 timeframe.

As of September 30, 2020, OTP had capitalized approximately $231.1 million in project costs and AFUDC associated with Merricourt. OTP estimates its direct generation and transmission capital costs for the Merricourt project will be approximately $260 million. Additional transmission system upgrades for the project amounting to approximately $6.4 million will be made by a neighboring MISO transmission owner. OTP has received Notices of Force Majeure from EDF-RE US Development, LLC claiming rights to an extension of guaranteed project completion dates and adjustments to the consideration agreed upon in the TEPC Agreement due to COVID-19 impacts. While details regarding these claims and impact to the project remain uncertain, OTP currently anticipates Merricourt will be in commercial operation before the end of December 2020. These and other potential impacts of COVID-19-related disruptions continue to present risks for the costs and timing of payments related to the project.

As of September 30, 2020, OTP had capitalized approximately $131.6 million in project costs and AFUDC associated with Astoria Station. OTP estimates its direct generation and transmission capital costs for the Astoria Station project will be approximately $152.5 million and anticipates the plant will begin commercial operation in the first quarter of 2021, prior to the planned retirement of Hoot Lake Plant in May 2021.

In September 2020, OTP announced plans for the construction of the $60 million Hoot Lake Solar project. This is a 49-megawatt project OTP expects to build on land around Hoot Lake Plant in Fergus Falls, Minnesota. The project is expected to include up to 170,000 solar panels and to generate enough energy to power approximately 10,000 homes each year. The project is targeted for completion in 2022.

Contractual Obligations

In the first nine months of 2020, OTP paid down a portion of its $317 million in obligations for commitments under contracts in place as of December 31, 2019, reducing its obligations for commitments under contracts to $58 million as of September 30, 2020. This includes commitments related to the construction of Astoria Station and Merricourt of $39 million for the remainder of 2020 and $6 million for 2021. In the first nine months of 2020, OTP increased its debt obligations by $75 million in the years beyond 2024. In September 2020, OTP entered into a 20-year Facilities Service Agreement with an owner of adjacent transmission assets to pay for upgrades and additions to the owner’s transmission facilities required to accommodate the transmission of electricity generated by Merricourt’s wind turbines, increasing its other purchase obligations by $1.4 million in each of the two-year periods 2021-2022 and 2023-2024, and $10.8 million beyond 2024.

Table of Contents

CAPITAL RESOURCES

On May 3, 2018 we filed a shelf registration statement with the Securities and Exchange Commission (SEC) under which we may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, which expires on May 3, 2021. On May 3, 2018 we also filed a shelf registration statement with the SEC for the issuance of up to 1,500,000 common shares under our Automatic Dividend Reinvestment and Share Purchase Plan (the Plan), which permits shares purchased by participants in the Plan to be either new issue common shares or common shares purchased in the open market. The shelf registration for the Plan expires on May 3, 2021. On November 8, 2019 the Company entered into a Distribution Agreement with KeyBanc under which we may offer and sell our common shares from time to time through KeyBanc, as our distribution agent, up to an aggregate sales price of $75 million through an At-the-Market offering program. In the third quarter of 2020, we received proceeds of $3,523,311, net of $44,599 in commissions, from the issuance of 87,400 common shares under this program.

Debt

Brief descriptions of the short-term and long-term credit and debt agreements currently in place at Otter Tail Corporation and OTP are presented below. See note 10 to our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2019 for additional information on the terms, provisions, restrictions and covenants under these agreements.

Short-Term Debt

On October 29, 2012 we entered into a Third Amended and Restated Credit Agreement (the OTC Credit Agreement), which provided for an unsecured $130 million revolving credit facility that could be increased subject to certain terms and conditions. On October 31, 2019 the OTC Credit Agreement was amended to extend its expiration date by one year from October 31, 2023 to October 31, 2024, and to increase the amount of the revolving credit facility to $170 million. The amendment also provides this facility can be increased to $290 million subject to certain terms and conditions. Borrowings under the OTC Credit Agreement bear interest at LIBOR plus 1.50%, subject to adjustment based on our senior unsecured credit ratings or the issuer rating if a rating is not provided for the senior unsecured credit.

On October 29, 2012 OTP entered into a Second Amended and Restated Credit Agreement (the OTP Credit Agreement), providing for an unsecured $170 million revolving credit facility that may be increased to $250 million subject to certain terms and conditions. On October 31, 2019 the OTP Credit Agreement was amended to extend its expiration date by one year from October 31, 2023 to October 31, 2024. OTP can draw on this credit facility to support the working capital needs and other capital requirements of its operations, including letters of credit in an aggregate amount not to exceed $50 million outstanding at any time. Borrowings under this line of credit bear interest at LIBOR plus 1.25%, subject to adjustment based on the ratings of OTP’s senior unsecured debt or the issuer rating if a rating is not provided for the senior unsecured debt.

Long-Term Debt

On September 12, 2019,OTP entered into a Note Purchase Agreement (the 2019 Note Purchase Agreement) with the purchasers named therein, pursuant to which OTP agreed to issue to the purchasers, in a private placement transaction, $175 million aggregate principal amount of OTP’s senior unsecured notes consisting of (a) $10,000,000 aggregate principal amount of its 3.07% Series 2019A Senior Unsecured Notes due October 10, 2029 (the Series 2019A Notes), (b) $26,000,000 aggregate principal amount of its 3.52% Series 2019B Senior Unsecured Notes due October 10, 2039 (the Series 2019B Notes), (c) $64,000,000 aggregate principal amount of its 3.82% Series 2019C Senior Unsecured Notes due October 10, 2049 (the Series 2019C Notes), (d) $10,000,000 aggregate principal amount of its 3.22% Series 2020A Senior Unsecured Notes due February 25, 2030 (the Series 2020A Notes), (e) $40,000,000 aggregate principal amount of its 3.22% Series 2020B Senior Unsecured Notes due August 20, 2030 (the Series 2020B Notes), (f) $10,000,000 aggregate principal amount of its 3.62% Series 2020C Senior Unsecured Notes due February 25, 2040 (the Series 2020C Notes) and (g) $15,000,000 aggregate principal amount of its 3.92% Series 2020D Senior Unsecured Notes due February 25, 2050 (the Series 2020D Notes).

On February 25, 2020, OTP issued the Series 2020A Notes, the Series 2020C Notes and the Series 2020D Notes pursuant to the 2019 Note Purchase Agreement. On August 20, 2020, OTP issued the Series 2020B Notes pursuant to the 2019 Note Purchase Agreement. OTP used the $75 million proceeds from the issuances to pay for capital expenditures and for other corporate purposes. The Series 2019A Notes, Series 2019B Notes and Series 2019C Notes were issued by OTP on October 10, 2019.

On February 27, 2018 OTP issued $100 million aggregate principal amount of its 4.07% Series 2018A Senior Unsecured Notes due February 7, 2048 pursuant to a Note Purchase Agreement dated as of November 14, 2017 (the 2018 Note Purchase Agreement).

Table of Contents

On December 13, 2016 Otter Tail Corporation issued $80 million aggregate principal amount of its 3.55% Guaranteed Senior Notes due December 15, 2026 (the 2026 Notes) pursuant to a Note Purchase Agreement dated as of September 23, 2016 (the 2016 Note Purchase Agreement). Our obligations under the 2016 Note Purchase Agreement and the 2026 Notes are guaranteed by our Material Subsidiaries (as defined in the 2016 Note Purchase Agreement, but specifically excluding OTP).

On February 27, 2014 OTP issued $60 million aggregate principal amount of its 4.68% Series A Senior Unsecured Notes due February 27, 2029 and $90 million aggregate principal amount of its 5.47% Series B Senior Unsecured Notes due February 27, 2044 pursuant to a Note Purchase Agreement dated as of August 14, 2013 (the 2013 Note Purchase Agreement).

On December 1, 2011 OTP issued $140 million aggregate principal amount of its 4.63% Senior Unsecured Notes due December 1, 2021 pursuant to a Note Purchase Agreement dated as of July 29, 2011 (the 2011 Note Purchase Agreement).

OTP also has outstanding its $122 million senior unsecured notes issued in three series consisting of $30 million aggregate principal amount of 6.15% Senior Unsecured Notes, Series B, due 2022; $42 million aggregate principal amount of 6.37% Senior Unsecured Notes, Series C, due 2027; and $50 million aggregate principal amount of 6.47% Senior Unsecured Notes, Series D, due 2037 (collectively, the 2007 Notes). The 2007 Notes were issued pursuant to a Note Purchase Agreement dated as of August 20, 2007 (the 2007 Note Purchase Agreement).

Financial Covenants

We were in compliance with the financial covenants in our debt agreements as of September 30, 2020.

No Credit Agreement or Note Purchase Agreement contains any provisions that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related obligor by rating agencies.

Our borrowing agreements are subject to certain financial covenants. Specifically:

●

Under the OTC Credit Agreement and the 2016 Note Purchase Agreement, we may not permit the ratio of our Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit our Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00 (each measured on a consolidated basis). As of September 30, 2020, our Interest and Dividend Coverage Ratio calculated under the requirements of the OTC Credit Agreement and the 2016 Note Purchase Agreement was 4.74 to 1.00.

●

Under the 2016 Note Purchase Agreement, we may not permit our Priority Indebtedness to exceed 10% of our Total Capitalization.

●

Under the OTP Credit Agreement, OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00.

●

Under the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, OTP may not permit the ratio of its Consolidated Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, in each case as provided in the related borrowing agreement, and OTP may not permit its Priority Debt to exceed 20% of its Total Capitalization, as provided in the related agreement. As of September 30, 2020, OTP’s Interest and Dividend Coverage Ratio and Interest Charges Coverage Ratio, calculated under the requirements of the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, was 3.91 to 1.00.

●

Under the 2013 Note Purchase Agreement, the 2018 Note Purchase Agreement, and the 2019 Note Purchase Agreement, OTP may not permit its Interest-bearing Debt to exceed 60% of Total Capitalization and may not permit its Priority Indebtedness to exceed 20% of its Total Capitalization, in each case as provided in the related agreement.

As of September 30, 2020, our ratio of Interest-bearing Debt to Total Capitalization was 0.49 to 1.00 on a consolidated basis and 0.47 to 1.00 for OTP. Neither Otter Tail Corporation nor OTP had any Priority Indebtedness outstanding as of September 30, 2020.

OFF-BALANCE-SHEET ARRANGEMENTS

We and our subsidiary companies have outstanding letters of credit totaling $12.1 million, but our line of credit borrowing limits are only restricted by $7.7 million in outstanding letters of credit. We do not have any other off-balance-sheet arrangements or any relationships with unconsolidated entities or financial partnerships. These entities are often referred to as structured finance special purpose entities or variable interest entities, which are established for the purpose of facilitating off-balance-sheet arrangements or for other contractually narrow or limited purposes. We are not exposed to any financing, liquidity, market or credit risk that could arise if we had such relationships.

Table of Contents

20 20 BUSINESS OUTLOOK

We are raising and narrowing our 2020 diluted earnings per share guidance range based on our financial results through the first nine months of 2020 and updated view of current business conditions in our Plastics and Manufacturing segments. We now expect our 2020 diluted earnings per share to be in the range of $2.26 to $2.36 instead of $2.10 to $2.30. This revision in guidance is primarily driven by strong performance in our Plastics segment along with continued favorable business conditions in this segment expected through the rest of 2020. Also, the impact of COVID-19 on our Electric segment has been less than previously expected. Our 2020 diluted earnings per share guidance includes $0.04 of dilution associated with actual and planned issuances of common shares under our At-the-Market Offering Program and Dividend Reinvestment and Employee Stock Purchase Plans to help fund construction projects at OTP.

We currently expect capital additions to be $380 million in 2020, with our Electric segment accounting for 96% of those additions, largely driven by the Merricourt and Astoria Station rate base projects. A five-year anticipated capital expenditures table is provided above on page 45.

Segment components of our revised 2020 diluted earnings per share guidance range compared with 2019 actual earnings and with our previously issued guidance are as follows.

	2019 EPS by			2020 Guidance February 20, 2020						2020 Guidance May 5, 2020						2020 Guidance August 3, 2020						2020 Guidance November 2, 2020
Diluted Earnings Per Share		Segment		Low			High			Low			High			Low			High			Low			High
Electric	$	1.48		$	1.67		$	1.70		$	1.65		$	1.70		$	1.67		$	1.70		$	1.67		$	1.69
Manufacturing	$	0.32		$	0.31		$	0.35		$	0.14		$	0.23		$	0.15		$	0.23		$	0.23		$	0.25
Plastics	$	0.51		$	0.43		$	0.47		$	0.43		$	0.47		$	0.50		$	0.54		$	0.64		$	0.66
Corporate	$	(0.14	)	$	(0.19	)	$	(0.15	)	$	(0.22	)	$	(0.15	)	$	(0.22	)	$	(0.17	)	$	(0.28	)	$	(0.24	)
Total	$	2.17		$	2.22		$	2.37		$	2.00		$	2.25		$	2.10		$	2.30		$	2.26		$	2.36
Return on Equity		11.6	%		11.0	%		11.7	%		9.9	%		11.1	%		10.4	%		11.4	%		11.2	%		11.7	%

The estimates and assumptions underlying our latest 2020 guidance (issued on November 2, 2020) as compared to earlier guidance (issued on August 3, 2020) are summarized below.

●

Our 2020 guidance for our Electric segment includes:

Capital spending on the Merricourt and Astoria Station rate base projects of $177 million and $81 million, respectively, in 2020. The Merricourt project has rider recovery mechanisms in place in all three state jurisdictions. The Astoria Station project has rider recovery mechanisms in place in South Dakota and North Dakota. This project earns allowance for funds used during construction in Minnesota, has already been approved in our integrated resource plan and is expected to be recovered through a general rate increase in Minnesota requested on November 2, 2020. The Astoria Station capital project is currently on budget, with commercial operation expected to begin in the first quarter of 2021. The Merricourt project continues to be on budget and is expected to be in commercial operation before the end of December 2020.

Increased revenues related to $25 million in anticipated capital spending for self-funded generator interconnection agreements.

No major planned generation plant maintenance outages for 2020. Plant outage costs totaled $3.1 million in 2019.

The April 2020 Minnesota Supreme Court decision in OTP’s favor related to the higher return earned on Federal Energy Regulatory Commission jurisdiction transmission lines. The estimated impact of this decision is an increase to 2020 earnings of $0.05 per share. This was reflected in our third quarter financial results. On a go-forward basis the positive impact of this decision on an annual basis is $0.01 per share. We have updated our Minnesota Transmission Cost Recovery rider filing with new rates incorporating the results of the decision to reflect the effect of this ruling.

A favorable impact of weather on 2020 earnings compared to the forecasted earnings under normal weather conditions of $0.02 per share through September 30, 2020.

The above items are offset by:

Reductions in commercial and industrial demand related to the negative impacts of COVID-19 as some customers in our jurisdictions have either completely shut down operations or curtailed operations given reduced demands for their products and services. We also expect to incur increased costs for bad debts, personal

Table of Contents

protective equipment and the loss of late fee revenue. The total estimated earnings impact of these items ranges from $0.06 per share to $0.08 per share. OTP continues to work on obtaining regulatory relief to mitigate the impact of COVID-19 on its operating results. Potential COVID-19-related items include items such as lost commercial and industrial revenues, lost late fees and added expenses for increased bad debts, personal protective equipment and other increased operating and maintenance expenses. Our current electric segment guidance does not assume recovery of any of these items in 2020.

Increased expenses caused in large part by a decrease in the discount rate used for the pension plan and a lower rate used for our long-term rate of return. The discount rate for 2020 is 3.47% compared with 4.50% for 2019. For each 25-basis-point decline in the discount rate, pension expense increases approximately $1.0 million. The assumed long-term rate of return for 2020 is 6.88% compared with 7.25% in 2019. Each 25-basis-point decline in this rate equates to approximately $0.7 million in increased pension expense.

A planned contribution to the Otter Tail Power Company Foundation of $0.02 per share.

Higher depreciation and property tax expense due to large capital projects being put into service.

Increased interest costs associated with a full year’s interest expense on $100 million of senior unsecured notes issued in October 2019 and interest on the $35 million and $40 million of senior unsecured notes issued in February and August of 2020, respectively.

●

We are raising and narrowing our guidance range for our Manufacturing segment:

We now estimate an increase of $0.05 per share from the mid-point of our August 3, 2020 guidance. The upward revision is driven by a stronger than expected recovery in the second half of 2020 as compared to our previous assumptions.

Backlog for the Manufacturing segment is approximately $63 million for 2020 compared with $56 million one year ago.

●

We are raising and narrowing our earnings guidance range for our Plastics segment. Sales volumes in 2020 are now forecasted to be approximately 5% higher than 2019 given strong results in the first nine months of 2020 and current market conditions. Market conditions continued to improve during the third quarter due to limited effects of COVID-19, two resin suppliers invoking force majeure which positively impacted PVC pipe sale prices, concerns over hurricanes creating limited availability of PVC resin supplies, significant global demand for PVC resin and limited PVC pipe inventory across the country. All of these factors contributed to increasing sales and raw material prices which have favorably impacted our financial results in the Plastics segment. Also included in this updated guidance is a planned contribution to Otter Tail Corporation’s Foundation of $0.03 per share.

●

Corporate costs, net of tax, are expected to be higher than 2019 and our previous 2020 guidance due to increases in employee benefit costs resulting from the significant increase in 2020 earnings and a planned contribution to Otter Tail Corporation’s Foundation of $0.03 per share.

Critical Accounting Policies Involving Significant Estimates

The discussion and analysis of the financial statements and results of operations are based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities.

We use estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used for such items as depreciable lives, asset impairment evaluations, tax provisions, collectability of trade accounts receivable, self-insurance programs, unbilled electric revenues, interim rate refunds, warranty reserves and actuarially determined benefits costs and liabilities. As better information becomes available or actual amounts are known, estimates are revised. Operating results can be affected by revised estimates. Actual results may differ from these estimates under different assumptions or conditions. Management has discussed the application of these critical accounting policies and the development of these estimates with the Audit Committee of the board of directors. A discussion of critical accounting policies is included under the caption “Critical Accounting Policies Involving Significant Estimates” on pages 57 through 59 of our Annual Report on Form 10-K for the year ended December 31, 2019. Aside from an interim test of goodwill impairment performed for our BTD reporting unit, which was performed during the quarter ended March 31, 2020 and is further described below, there have been no material changes in critical accounting policies or estimates.

Table of Contents

Goodwill is required to be tested annually for impairment and more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Examples of such events or circumstances may include, among others, a significant adverse change in business climate, weakness in an industry in which a reporting unit operates or recent significant cash or operating losses with expectations that those losses will continue. Goodwill is tested for impairment at the reporting unit level. A reporting unit is defined as an operating segment or one level below an operating segment (referred to as a component). A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and segment management regularly reviews the operating results of that component.

During the quarter ended March 31, 2020, the Company concluded an interim impairment test of goodwill of its BTD reporting unit, which carries a goodwill balance of $18.1 million, was warranted. This conclusion was reached based on the deteriorating economic conditions resulting from COVID-19 that led to lower product demand across all end markets beginning in the last half of March 2020 and the anticipation of subsequent further reduced demand resulting from temporary plant shutdowns of our original equipment manufacturer customers. In response to this reduced demand, BTD has reduced its operating levels and implemented certain cost reduction efforts, including temporary furloughs of production employees.

We estimated the fair value of the BTD reporting unit primarily using an income approach, which includes a discounted cash flow methodology to arrive at a fair value estimate by determining the present value of projected future cash flows over a specified period plus a terminal value related to cash flows beyond the projection period. The discount rate applied to the estimated future cash flows reflects our estimate of the weighted-average cost of capital of comparable companies. To supplement our income approach, we reference various market indications of fair value, where available. Our market approach includes fair value estimates using multiples derived from comparable enterprise values to EBITDA and revenue multiples, comparable price earnings ratios and, if available, comparable sales transactions for comparative peer companies.

The impairment assessment indicated no impairment was present as the estimated fair value of the reporting unit exceeded the carrying value by approximately 20%. The most significant assumption impacting our fair value estimate under the income approach is the anticipated duration and severity of reduced demand and the resulting impact on revenue levels given the uncertainty of economic conditions in light of COVID-19. Our assumptions included significantly reduced demand in the second quarter of 2020 followed by recovering levels of demand in the third and fourth quarters of 2020. Other significant assumptions included operating expense levels and our ability to manage costs during the anticipated period of reduced demand, the terminal growth rate which impacts estimated cash flow generation beyond our discrete projection period, and the discount rate applied to our estimated future cash flows.

Our estimates and assumptions inherently include a degree of uncertainty, and these estimates and assumptions could be significantly impacted by factors such as the duration and severity of reduced economic activity and industry conditions within the recreational vehicle, lawn and garden, construction, agricultural, and industrial and energy equipment end markets. A significant change in our estimates and assumptions could result in an impairment charge in a future period which could materially impact our results of operations and financial position.

Forward Looking Information - Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995

In connection with the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995 (the Act), we have filed cautionary statements identifying important factors that could cause our actual results to differ materially from those discussed in forward-looking statements made by or on behalf of the Company. When used in this Form 10-Q and in future filings by the Company with the Securities and Exchange Commission, in our press releases and in oral statements, words such as "may", "will", "expect", "anticipate", "continue", "estimate", "project", "believes" or similar expressions are intended to identify forward-looking statements within the meaning of the Act and are included, along with this statement, for purposes of complying with the safe harbor provision of the Act. These forward-looking statements involve risks and uncertainties. Actual results may differ materially from those contemplated by the forward-looking statements due to, among other factors, the risks and uncertainties described in the section entitled “Risk Factors” in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2019, and in Part II, Item 1A of our Quarterly Report on Form 10-Q for the quarters ended June 30, 2020 and September 30, 2020, as well as the various factors described below:

●

The economic effects of the COVID-19 pandemic and measures taken to arrest its spread, as well as any emergency measures we are forced to take in response, could continue to adversely impact our business, including our results of operations, financial condition and liquidity.

●

Federal and state environmental regulation could require us to incur substantial capital expenditures and increased operating costs.

Table of Contents

●

Weather impacts, including normal seasonal fluctuation of weather, as well as extreme weather events that could be associated with climate change, could adversely affect our results of operations.

●

Volatile financial markets and changes in our debt ratings could restrict our ability to access capital and increase borrowing costs and pension plan and postretirement health care expenses.

●

Any significant impairment of our goodwill would cause a decrease in our asset values and a reduction in our net operating income.

●

The inability of our subsidiaries to provide sufficient earnings and cash flows to allow us to meet our financial obligations and debt covenants and pay dividends to our shareholders could have an adverse effect on the Company.

●

We rely on our information systems to conduct our business, and failure to protect these systems against security breaches or cyber-attacks could adversely affect our business and results of operations. Additionally, if these systems fail or become unavailable for any significant period, our business could be harmed.

●

Economic conditions could negatively impact our businesses.

●

If we are unable to achieve the organic growth we expect, our financial performance may be adversely affected.

●

Our plans to grow our businesses through capital projects, including infrastructure and new technology additions, or to grow or realign our businesses through acquisitions or dispositions may not be successful, which could result in poor financial performance.

●

We may, from time to time, sell assets to provide capital to fund investments in our electric utility business or for other corporate purposes, which could result in the recognition of a loss on the sale of any assets sold and other potential liabilities. The sale of any of our businesses also exposes us to additional risks associated with indemnification obligations under the applicable sales agreements and any related disputes.

●

Significant warranty claims and remediation costs in excess of amounts normally reserved for such items could adversely affect our results of operations and financial condition.

●

We are subject to risks associated with energy markets.

●

Changes in tax laws, as well as judgments and estimates used in the determination of tax-related asset and liability amounts, could materially adversely affect our business, financial condition, results of operations and prospects.

●

Four of our operating companies have single customers that provide a significant portion of the individual operating company’s and the business segment’s revenue. The loss of, or significant reduction in revenue from, any one of these customers would have a significant negative financial impact on the operating company and its business segment and could have a significant negative financial impact on the Company.

●

The inability to attract and retain a qualified workforce including, but not limited to, executive officers, key employees and employees with specialized skills could have an adverse effect on our operations.

●

We may experience fluctuations in revenues and expenses related to our electric operations, which may cause our financial results to fluctuate and could impair our ability to make distributions to shareholders or scheduled payments on our debt obligations, or to meet covenants under our borrowing agreements.

●

Actions by the regulators of our electric operations could result in rate reductions, lower revenues and earnings or delays in recovering capital expenditures.

●

OTP’s operations are subject to an extensive legal and regulatory framework under federal and state laws as well as regulations imposed by other organizations that may have a negative impact on our business and results of operations.

●

OTP’s electric transmission and generation facilities could be vulnerable to cyber and physical attack that could impair our ability to provide electrical service to our customers or disrupt the U.S. bulk power system.

●

OTP’s electric generating facilities are subject to operational risks that could result in early closure, unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.

●

Regulation of generating plant emissions could affect our operating costs and the costs of supplying electricity to our customers and the economic viability of continued operation of certain of OTP’s steam-powered electric plants.

●

The long-range planning required for transmission and generation projects creates risks of increased costs and lower returns on investment when the project is finally completed.

●

Competition from foreign and domestic manufacturers, the price and availability of raw materials, trade policy and tariffs affecting prices and markets for raw material and manufactured products, prices and supply of scrap or recyclable material and general economic conditions could affect the revenues and earnings of our manufacturing businesses.

Table of Contents

●

Economic conditions in the industries in which our customers operate can have an adverse impact on our results of operations and cash flows.

●

Our business and operating results may be adversely affected if we are not able to maintain our manufacturing, engineering and technological expertise.

●

Our manufacturing, painting and coating operations are subject to environmental, health and safety laws and regulations that could result in liabilities to us.

●

Our plastics operations are highly dependent on a limited number of vendors for PVC resin and a limited supply of PVC resin. The loss of a key vendor, or any interruption or delay in the supply of PVC resin, could result in reduced sales or increased costs for our plastics business.

●

We compete against many other manufacturers of PVC pipe and manufacturers of alternative products. Customers may not distinguish our products from those of our competitors.

●

Changes in PVC resin prices can negatively affect our plastics business.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

At September 30, 2020 we had exposure to market risk associated with interest rates because we had $48.6 million in short-term debt outstanding subject to variable interest rates indexed to LIBOR plus 1.50% under the OTC Credit Agreement.

All of our remaining consolidated long-term debt outstanding on September 30, 2020 has fixed interest rates. We manage our interest rate risk through the issuance of fixed-rate debt with varying maturities, through economic refunding of debt through optional refundings, limiting the amount of variable interest rate debt, and the utilization of short-term borrowings to allow flexibility in the timing and placement of long-term debt.

We have not used interest rate swaps to manage net exposure to interest rate changes related to our portfolio of borrowings. We maintain a ratio of fixed-rate debt to total debt within a certain range. It is our policy to enter into interest rate transactions and other financial instruments only to the extent considered necessary to meet our stated objectives. We do not enter into interest rate transactions for speculative or trading purposes.

The companies in our Manufacturing segment are exposed to market risk related to changes in commodity prices for steel, aluminum, and polystyrene and other plastics resins. The price and availability of these raw materials could affect the revenues and earnings of our Manufacturing segment.

The PVC pipe companies are exposed to market risk related to changes in commodity prices for PVC resins, the raw material used to manufacture PVC pipe. The PVC pipe industry is highly sensitive to commodity raw material pricing volatility. Historically, when resin prices are rising or stable, sales volume has been higher and when resin prices are falling, sales volume has been lower. Operating income may decline when the supply of PVC pipe increases faster than demand. Due to the commodity nature of PVC resin and the dynamic supply and demand factors worldwide, it is very difficult to predict gross margin percentages or to assume that historical trends will continue.

Item 4. Controls and Procedures

Under the supervision and with the participation of company management, including our Chief Executive Officer and Chief Financial Officer, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of September 30, 2020, the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2020.

During the fiscal quarter ended September 30, 2020, there were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Table of Contents

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We are the subject of various legal and regulatory proceedings in the ordinary course of our business. Such matters are subject to many uncertainties and to outcomes that are not predictable with assurance. We record a liability in our consolidated financial statements for costs related to claims, including future legal costs, settlements and judgments, where we have assessed that a loss is probable, and an amount can be reasonably estimated. Material proceedings are described under note 3, “Rate and Regulatory Matters” and note 9, "Commitments and Contingencies" to the consolidated financial statements.

Item 1A. Risk Factors

Aside from the additional risk factor described below and in Part II, Item 1A of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, there has been no material change in the risk factors set forth under Part I, Item 1A, “Risk Factors” on pages 29 through 39 of our Annual Report on Form 10-K for the year ended December 31, 2019.

The economic effects of the COVID-19 pandemic and measures taken to arrest its spread , as well as any emergency measures we take in response, could continue to adversely impact our business, including our results of operations, financial condition and liquidity.

The outbreak and global spread of COVID-19, which has been declared a pandemic by the World Health Organization, has adversely impacted economic activity and conditions worldwide and is currently impacting our business operations. The extent to which COVID-19 will continue to impact our business is highly uncertain and will depend on future developments and the extent of federal, state and local government responses affecting the economy. In particular, the COVID-19 pandemic could, among other things:

●

further reduce customer demand in our Manufacturing segment, where we have experienced a significant decline in orders as many of our customers are in businesses impacted by the pandemic and have temporarily closed their plants, and where we have already taken steps to reduce our operations, including furloughing of employees and eliminating positions;

●

further reduce customer demand in our Electric segment, including demand from commercial and industrial customers;

●

result in lower PVC pipe sales due to potential delays or cancellation of public water and wastewater infrastructure projects caused by funding shortfalls;

●

lead to disruptions of our workforce;

●

force us to temporarily close certain plants or construction sites if precautions to prevent the spread of the virus at those locations are not effective;

●

increase our bad debt expenses, particularly in our Electric segment;

●

increase our future pension benefit cost and funding requirements;

●

increase health insurance premiums;

●

disrupt the supply chains, delivery systems or construction workforce related to our Electric segment maintenance requirements and capital expenditure plans, including our Merricourt and Astoria Station projects, resulting in further delays and increased costs;

●

disrupt global financial markets, reducing our ability to access capital necessary to finance such expenditures, and which could in the future negatively affect our liquidity; and

●

result in a recession or market correction that could materially affect our business and the value of our common stock.

We continue to monitor developments involving our workforce, customers, construction contractors, suppliers and vendors and take steps to mitigate against additional impacts, but given the unprecedented and dynamic nature of these circumstances, we cannot predict the full extent of the impact that COVID-19 will have on our results of operations, financial condition and liquidity. The situation continues to change, and the magnitude of the impact will depend, in part, on the length and severity of the pandemic. However, the effects could have a material impact on our results of operations, financial condition and liquidity and heighten many of the known risks described under Part I, Item 1A, “Risk Factors” on pages 29 through 39 of our Annual Report on Form 10-K for the year ended December 31, 2019.

Table of Contents

Item 6. Exhibits

31.1

Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.SCH

Inline XBRL Taxonomy Extension Schema Document.

101.CAL

Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.LAB

Inline XBRL Taxonomy Extension Label Linkbase Document.

101.PRE

Inline XBRL Taxonomy Extension Presentation Linkbase Document.

101.DEF

Inline XBRL Taxonomy Extension Definition Linkbase Document.

104

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

OTTER TAIL CORPORATION

By: /s/ Kevin G. Moug

Kevin G. Moug
Chief Financial Officer and Senior Vice President
(Chief Financial Officer/Authorized Officer)

Dated: November 6 , 20 20

TABLE OF CONTENTS

Item 2. Management's Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II. Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 6. Exhibits

Exhibits

31.1 Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1 Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

OTTR 10-Q Quarter ended Sept. 30, 2020

Exhibits